Pillar Fracturing

ABSTRACT

A system and method for hydraulic fracturing a subterranean formation with fracturing fluid to generate fractures, and intermittently adjusting a characteristic of the fracturing fluid conveying proppant to form pillars of proppant in the fractures.

CROSS REFERENCE TO RELATED PATENT APPLICATIONS

This application is a divisional of and claims the benefit of priorityto U.S. patent application Ser. No. 16/928,926, filed Jul. 14, 2020, thecontents of which are incorporated by reference herein.

TECHNICAL FIELD

This disclosure relates to pillar fracturing which is hydraulicfracturing of a subterranean formation and forming pillars of proppantin the fractures.

BACKGROUND

Hydraulic fracturing employs fluid and material to generate fractures ina geological formation to stimulate production from oil and gas wells.Hydraulic fracturing is a well-stimulation technique in which rock isfractured by a pressurized fluid that may be a fracturing fluid. Theprocess can involve the hydraulic pressure of fracturing fluid into awellbore to initiate and propagate fracture in the deep-rock formationswhere sand and/or proppant may be placed through which reservoir oil,gas, water and pumped fluids will flow more freely. The fracturingtypically generates conductive paths that increase the rate at whichproduction fluids, such as crude oil or natural gas, can be producedfrom the reservoir formations. The amount of increased production may berelated to the stimulated reservoir volume. Proppant selection andproppant placement techniques may be enhanced to maintain the conductivefractures as pressure depletes in the well during hydrocarbonproduction. The selection of appropriate type of proppant may resistformation closure stresses to keep fractures open throughout theproducing life. Hydraulic fracturing may allow for the recovery of crudeoil and natural gas from unconventional formations that geologists oncebelieved were impossible to produce.

SUMMARY

An aspect relates to a method of hydraulic fracturing, includingproviding a fracturing fluid through a wellbore into a subterraneanformation and hydraulically fracturing the subterranean formation withthe fracturing fluid, thereby generating fractures in the subterraneanformation. The method includes conveying proppant in the fracturingfluid through the wellbore into the fractures. The method includesintermittently adjusting a characteristic of the fracturing fluidconveying the proppant to form pillars of proppant in the fractures.

Another aspect relates to a system for hydraulic fracturing. The systemincludes a source of fracturing fluid. The system includes pumpsoperationally coupled to the source to provide the fracturing fluidthrough a wellbore into a subterranean formation to hydraulicallyfracture the subterranean formation to generate fractures in thesubterranean formation, wherein the fracturing fluid to convey proppantinto the fractures. The system includes a control system tointermittently adjust a characteristic of the fracturing fluid conveyingthe proppant to form pillars of proppant in the fractures.

The details of one or more implementations are set forth in theaccompanying drawings and the description below. Other features andadvantages will be apparent from the description and drawings, and fromthe claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a diagram of a well site having a wellbore formed through theEarth surface into a subterranean formation in the Earth crust.

FIG. 2 is a diagram of hydraulic fractures having pillars of proppantdisposed in the fractures 200.

FIG. 3 is a block flow diagram of a method of hydraulic fracturing asubterranean formation, including to form pillars (accumulations) ofproppant in the generated fractures.

FIG. 4A and FIG. 4B are diagrams depicting a reaction that forms anexample functionalized nanoparticle to be included with unfunctionalizedorganic resin and a strengthening agent in resin coating of proppant.

FIG. 5 is a diagram of an example of an epoxy terminal binding group ona functionalized nanoparticle included in resin coating.

FIG. 6 is a block flow diagram of a method of forming a ceramic-coatedproppant including receiving core particles, which may be ceramicproppant or non-ceramic proppant.

FIG. 7 is a diagram of a proppant having a core particle and a ceramiccoating, and therefore may be characterized as a ceramic-coated particleor ceramic coated proppant.

FIG. 8 is a diagram of the ceramic-coated proppant of FIG. 7 having andadditional coating that is a polymer coating (an outer polymer layer),and therefore may be characterized as double coated.

Like reference numbers and designations in the various drawings indicatelike elements.

DETAILED DESCRIPTION

Embodiments of the present techniques involve hydraulic fracturing asubterranean formation with fracturing fluid to generate fractures, andintermittently adjusting a characteristic of the fracturing fluidconveying proppant to form pillars of proppant in the fractures. Inimplementations, the fracturing fluid is a single type of fracturingfluid. Variables of the fracturing fluid affecting the proppantsuspension and transport capacity of the specific fracturing-fluidsystem may be varied or pulsed to form the pillars.

The present disclosure is generally directed to pillar fracturing.Pillar fracturing may be hydraulic fracturing of a subterraneanformation and forming pillars of proppant in fractures. Advancedproppant may be utilized. The proppant may include coated sand, coatedceramics, and other materials as proppants. Some aspects of the presentdisclosure are directed to repeatedly altering a property (e.g.,alternating between values) of the fracturing fluid conveying theproppant to give a segregated distribution of proppant in the fracturesto form pillars of proppant in the fractures. The altering of theproperty may occur, for example, at a frequency at a time interval inthe range of 1 minute to 2 hours. Advantageously, in implementations, asingle type of fracturing fluid may be employed for the pillarfracturing. Thus, pulsing of two types of fracturing fluids may beavoided in forming the pillars. Instead, a property or characteristic ofthe fracturing may be alternated between (cycled through) a first valueand a second value. The property may be alternated between more than twovalues.

In certain implementations, the property alternated may be acharacteristic of the fracturing fluid, such as a concentration of acomponent in the fracturing fluid. In some embodiments, the propertyintermittently adjusted is rheology or rheological property of thefracturing fluid, such as viscosity, viscoelasticity, shear thinning,shear thickening, latent fluid, yield stress fluids, and so forth. Eachof these rheology factors may have a different effect on fluid pumping,proppant transport, and suspension of proppant in fluid. Some of theserheological properties may depend on concentration of polymer in fluidand the association of the properties with each other, and the like.

In some implementations, the fracturing fluid is foam fracturing fluidto perform the hydraulic fracturing and convey proppant to thefractures. Embodiments of the present techniques include pillarfracturing through controlled foam quality of the foam fracturing fluid.In particular, the (foam quality may be pulsed or varied, and/or foamingsurfactant may be pulsed or varied, and the like. Certain embodimentsutilize non-foam fracturing fluid, such as a viscoelastic surfactant(VES) based fracturing fluid. For the example of a VES fracturing fluid,some aspects are directed to achieving proppant pillars throughcontrolled application of VES concentration, brine concentration, ornanoparticles, or any combinations thereof. The “brine concentration”may refer to the salt concentration or salinity of the brine used as abase fluid of the fracturing fluid. The greater the brine concentrationof the brine, the greater the salinity of the brine.

An outcome or result with embodiments may include extended proppedhalf-length and solids-free hydrocarbon production along with promptrecovery of pumped fluids. Solids free hydrocarbon production may meanno solids or insignificant quantities of solids (in producedoil/gas/water) that could cause damage to the surface and plant facilityequipment. Such solids when present can be formation fines,crushed/uncrushed proppant, other pumped solids additives, etc. Theformation of pillars may give high fracture conductivity. The higher thefracture conductivity, the lower is the drawdown pressure to produce thewell. The lower the drawdown pressure, the lesser is the total solidsproduction. In some cases, infinite conductivity may be approached withpillar fracturing having significant open space is between pillars.Advanced proppant can further contribute towards enhancing fracturingconductivity and reducing drawdown pressure. Therefore, advancedproppant can also contribute towards achieving solids free production.

For embodiments, the pulsing or intermittent adjusting of afracturing-fluid property may refer to a single fracturing fluid orsingle type of fracturing fluid (e.g., foam fracturing fluid) in a givenapplication. In other words, the pulsing or intermittent varyinggenerally does not refer to alternating two different types or stages offracturing fluid (e.g., VES fluid alternated with a polymer fluid).Instead, a property (e.g., rheology) of the same fracturing fluid orsame type of fracturing fluid (e.g., VES fluid) is intermittentlyadjusted or pulsed. Thus, for a given application, advantageously onetype of fracturing fluid (not stages of different types of fracturingfluid) may be employed to form the pillars of proppant. The pillars maybe accumulations of proppant in the fractures. Regions or channels inthe fracture with less or no proppant may separate the respectivepillars.

Foam fracturing fluid may be employed in the hydraulic fracturing andformation of the proppant pillars. The foam fracturing fluid may have agas phase as an internal phase and a liquid phase as an external phase.The gas in the gas phase may include, for example, nitrogen (N2) orcarbon dioxide (CO2), or both. The liquid in the liquid phase may befresh water or saline water with other additives such as surfactants,clay inhibitors, buffer, gelling agents and the like. The foamfracturing fluid may include a foaming surfactant (foamer) at aspecified concentration and a specified foam quality for foam stabilityto transport proppant along the hydraulic fracture. Foam fluid can alsobe prepared from gelled or crosslinked fluid e.g., linear guar orcrosslinked guar based fluid. Foam quality is the volume percent of gascontent in the foam fracturing fluid. Thus, the foam quality may be thevolume percent of N2 or CO2, or both, in the foam fracturing fluid. Inimplementations, the foam quality (FQ) may be, for example, in the rangebetween 52% and 80%. The pillars can be formed by varying FQ orfoaming-surfactant concentration, or both. The varying may involvepulsing values for FQ or foaming-surfactant concentration. An example ofpulsing foaming agent in a foam system may be in repeating sequence toadd (or increased addition) and not add (or decreased addition) foamingagent to the fracturing fluid give the desired repeated upper and lowerconcentrations of the foaming agent surfactant in the fracturing fluid.The values of FQ (or foaming-agent concentration) to alternate betweenmay be initially determined, for example, via foam rheology tests in thelaboratory at downhole conditions.

The time interval (frequency) of the sequence in alternating between thetwo or more values of FQ may be specified based, for example, on thefoam rheology profile at downhole conditions and the subterraneanformation (reservoir) transmissibility or permeability. The timeinterval (frequency) of the sequence may be less in a reservoir withhigh transmissibility than for a reservoir with low transmissibility. Ina gas reservoir, reservoir permeability higher than 5 millidarcy (mD)can be considered a high-permeability reservoir and lower than 0.5 mDcan be considered low-permeability reservoir. However, otherpetrophysics and rock mechanical properties (e.g., porosity, net pay,leak-off height, transmissibility, closure stress, Young's modulus,Poisson's ratio, etc.) may also be considered to calibrate low and hightransmissibility reservoirs in a specific field.

Young's modulus and Poisson's ratio may be utilized to determine if thesubterranean formation is stiff or ductile. For a stiff subterraneanformation, the pillars may be further apart. For a ductile subterraneanformation, the pillars may be closer to each other. This considerationof stiff or ductile may contribute to determining and specifying thetime interval of the sequence in the alternating or cycling between thetwo or more values of FQ or other characteristic of the fracturingfluid.

The controlled varying of FQ and/or foaming-surfactant concentration insequences may segregate proppant as delivered (dropped from suspension)to generate (form) the pillars. The regions between the pillars maygenerally be conductive and give significant contribution to theconductivity. The pillars of proppant formed may generally beconductive. The pillars themselves may conductive to contribute someconductivity because there may be voids or small channels within apillar. The conductivity within a pillar is generally less than theconductivity regions between the pillars. The enhanced proppant mayincrease conductivity within the pillar.

The FQ can be varied, for example, within the foam regime of FQ between52% and 80% while maintaining the same or similar total downhole pumpingrate. An example of pulsing FQ may be stopping gas addition and startinggas addition to the foaming fracturing fluid to give desired lower andupper values of FQ during the treatment. In a foam system, the FQ can bevaried by increasing or decreasing gas rate to the fracturing fluid anddecreasing or increasing liquid rate to the fracturing fluid for thesame or different total downhole rate of the fracturing fluid. The FQadjustments can be performed on the fly. To control FQ, the additionrate of gas (e.g., N2 or CO2) injected into the fracturing fluid as thefracturing fluid is being pumped may be adjusted. A liquid (water)addition rate to the fracturing fluid may be adjusted to control FQ.Some examples of controlling FQ include: (1) increasing gas rate anddecreasing liquid rate (FQ will increase and same total downhole ratecan be maintained); (2) increasing liquid rate and decreasing gas rate(FQ will decrease and same total downhole rate can be maintained); (3)increasing liquid and gas rate (total downhole rate will be increased,while FQ can be maintained the same); and (4) decreasing liquid and gasrate (total downhole rate will be decreased, while FQ can be maintainedthe same). Other examples may involve increasing and decreasing thesurfactant concentration to alternate between stable foam andless-stable foam (e.g., low-stable foam or unstable foam) whilemaintaining the gas concentration generally constant. This may alterrheology of fluid in the cycle and thus alternate the proppant carryingcapacity in the cycle to form pillars.

For embodiments in which a VES-based fracturing fluid is employed, theVES-based fracturing fluid may suspend and carry proppant due to viscousand elastic properties of VES including with brine (salt). VES-basedhydraulic fracturing fluids may be a cleaner alternative topolymer-based systems. For the VES-based fracturing fluid, the VESconcentration, brine (salt) type, and brine (salt) concentration may bespecified. Specifying the salt concentration in the brine incorporatedinto the fracturing fluid may give a specified salt concentration in thefracturing fluid. Further, the addition of microparticles ornanoparticles can further influence the proppant suspension capacity ofthe VES-based fracturing fluid including at high temperature (e.g.,above 300° C.). High temperature may be significant in relation to thepresence of microparticles and/or nanoparticles. In general, theviscosity profile can be significantly enhanced at higher temperatureswith use of microparticles or nanoparticles, for example. Microparticlesand nanoparticles in some cases provide stability to wormlike micellespresent in the VES fluid and thus the fluid stability at highertemperature. There may be interactions between charges on surfactant andparticle that behave as crosslinking mechanism to give stability ofmicelles.

For applications utilizing VES fracturing fluid, one or more of thefollowing actions or variables can be varied (pulsed) to segregateproppant in a controlled manner to create conductive pillars duringhydraulic fracturing: (1) concentration of VES in the fracturing fluid,(2) salt concentration of brine (or brine substitute) incorporated inthe fracturing fluid, and (3) addition of microparticles ornanoparticles. The concentration of brine is the concentration of saltin the brine, e.g., the salinity of the brine. This brine concentration(brine salinity) can be as low as in a range of 500 ppm to 2000 ppm saltin fresh water up to as much as 40 wt % salt concentration in water.Brine may an additive incorporated into the fracturing fluid at theEarth surface. Brine may be utilized to formulate VES fluids system onsurface. Brine may generally be water with salt. Brine may be formed byadding salt to water. For instance, when potassium chloride (KCl) saltis added to water, the formed brine may be labeled as KCl brine. In thatinstance, depending on KCl concentration, the brine may be namedaccordingly (e.g., 6% KCl brine, 10% KCl brine, etc.). Altering the saltconcentration in the brine incorporated into the fracturing fluid altersthe salt concentration in the fracturing fluid.

The pulsing/varying of the above mentioned variables (1), (2), and (3),and other variables, may affect the proppant suspension capacity byaltering viscoelasticity or viscosity. In the portions or intervals ofthe sequence in which viscosity is reduced, the specifying of theaforementioned variables may break long wormlike micelles into sphericalshapes in the VES-based fracturing fluid during those intervals of thesequence and in a controlled manner. The proppant suspension capacitymay be the amount proppant that the fracturing fluid can carry withoutscreen out. Screen out may mean that when the fracturing fluid cannotcarry all of the proppant, proppant settles out of the fracturing fluidwhile being pumped, plugging the piping and perforations and causing thefracturing job to stop. Generally, proppant suspension capacity ortransport of proppant in fluid may be given in mass of proppant pervolume of fluid. In static conditions for some carrying fluids, theproppant can settle at lower concentration or more quickly with thecarrying fluid at static conditions. The proppant may settle at greaterconcentration or less quickly during pumping of the carrying fluid.

When VES is added into water, the VES molecules may associate intostructures called micelles. In the presence of desired or optimum brineconcentration (e.g., beneficial values of KCl concentration, CaCl2)concentration, etc.), the micelles may become a rodlike shape. If theVES is present is sufficient concentration, the micelles associate witheach other. The resulting hindered movement make the fracturing fluidboth viscous and elastic that suspends and carry proppant during thefracturing treatment. VES fluids are typically sensitive to temperature.The settling of proppant should be generally be less during pumping anduntil fracture closes on proppant after pumping.

It should be understood that the phrase “VES fluid” may generally referto a “VES-based fluid” in that the “VES fluid” contains more than a VES.Similarly, the phrase “VES hydraulic fracturing fluid” generally refersto “VES-based hydraulic fracturing fluid” in that the hydraulicfracturing fluid. In addition to having VES, a VES-based hydraulicfracturing fluid may have other additives, such as clay inhibitors,buffers, scale inhibitors, biocide, polymers, crosslinking agents,nanoparticles, breaker, etc. Further, a VES-based fluid having the VESmay include mono or multivalent brine as a base fluid. The VES-basedfluid having the VES may include water as a base fluid with salt (e.g.,mono or multivalent salt) added.

The brine concentration (brine salinity) may be adjusted. For VESfracturing fluid, different concentrations (e.g., typically twoconcentrations) of brine may be utilized. One concentration may giveviscous and elastic properties, while the other concentration may behigher or lower brine concentration to provide lesser suspensioncapacity of proppant to allow desired proppant settlement to createpillars. This adjustment of viscoelastic properties and formation ofpillars can also be implemented with VES concentration (VES) in thefracturing fluid. The brine may typically be batch-mixed with thefracturing fluid. Generally, other additives (e.g., VES, nanoparticles,stabilizer, breaker, crosslinker, etc.) can be added on-the-fly to thefracturing fluid.

For both non-foam fracturing fluids (e.g., VES fracturing fluid) andfoam fracturing fluids, the effect of intermittently changing (pulsing)a fracturing-fluid property may be correlative with the transmissibilityof the subterranean formation. In particular, the impact of periodicallyadjusting (pulsing) the fracturing-fluid property (and proppant pulsing)on fracturing-fluid proppant concentration and the magnitude of proppantsegregation may depend on the transmissibility or permeability of thesubterranean formation (reservoir). The transmissibility or permeabilitymay typically be determined from mini-fall-off tests. A mini-fall-offtest (or minifrac test) may be an injection-falloff diagnostic testperformed without proppant before a main fracture stimulation treatment.The intent may be to break down the formation to create a short fractureduring the injection period, and then to observe closure of the fracturesystem during the ensuing falloff period.

Again, the aforementioned variables associated with the fracturing fluidmay be affected by (correlative with) transmissibility or permeabilityof the formation. In a subterranean formation with hightransmissibility, the proppant segregation mechanism may be lessaggressive and proppant pulsing sequence less frequent. For tight or lowtransmissibility in the subterranean formation, the proppant segregationmechanism may be more aggressive and proppant pulsing more frequent.Transmissibility may be the flow conductivity of the formation correctedfor viscosity of the flowing fluid. Transmissibility may be the productkh of permeability (k) and thickness (h) divided by fluid viscosity. Inparticular, an equation for transmissibility may be kh/μ, where k isformation permeability, h is the producing formation thickness (h) in aproducing well, and μ is viscosity.

Embodiments may be directed to pillar fracturing and flow-conductivityenhancement in a subterranean formation that is a high-stress reservoir(e.g., having stress and stress gradient greater than 10,000 pounds persquare inch (psi) and 0.7 psi per foot. Conductivity enhancement may beachieved at least through: (1) proppant segregation to create conductiveinter-pillar channels in low-transmissibility formations; (2) increasedwidth and generation of high net pressure in high-transmissibilityformations; (3) periodic varying or pulsing (with zero or negligiblesand/proppant concentration) to further stabilize conductive channelsand facilitate fracture placement; and (4) nanocomposite resin andceramic matrix coating of sand and proppant. The ceramic matrix coatingincludes a ceramic matrix composite (CMC). The inclusion of alkylfluoro-silanes as low surface-energy modifier to proppant includingnanocomposite resin and CMC coating may expedite recovery of pumpedfluids, prevent or reduce water block, and further enhance fractureconductivity.

Proppant having advanced coating may be utilized. The advanced coatingmay include nanocomposite resin coating, ceramic coating with ceramicmatrix composite (CMC), and other coatings. The underlying proppantparticle having the coating may be ceramic, metal, sand, and so on. Insome embodiments, the proppant may be sand coated with ceramic. Thecrush resistance strength, unconfined compressive strength (UCS), andretained permeability of sand and proppant can be increased by advancedcoating technology including nanocomposite resin and CMC. Theseresin-coated sands (RCS) and resin-coated proppants (RCP) may generallyreduce the proppant bulk density as light-weight nanocomposite coatingand filler materials are introduced. This reduction in proppant bulkdensity may further increase the suspension capacity of the RCS and RCP.Fines migration may be controlled or reduced by employment of proppant(or sand) coated with the advanced nanocomposite resin or ceramic matrixcoating. Advanced coating can also be done on the fly with resins suchas novolac, Resole, epoxy, urethane and others. In subterraneanenvironment they will make particle aggregate and fuse to form pillars.Coated proppant can have curable resins which in formation may formpillars with good strength.

With the fracturing fluid conveying proppant, RCS, or RCP to thefractures, the fracturing fluid can be applied at intermittent periods(pulsed) with negligible proppant concentration. This may furtherincrease fracture conductivity and potential for fracture placementwithout screen-out especially in completion with limited bottomholepressure tolerance. The fracture placement may refer to the designedvolume of sand, proppant, RCS, or RCP placed in the formation withinsurface and bottom hole pressure limits and without prematurescreen-out. Screen-out may be a condition (e.g., bridging of proppantacross casing perforations and/or in the hydraulic fracture) giving arestriction to flow of fracturing fluid and thus causing an increase insurface and bottom hole treatment pressure that often forces toprematurely terminate the fracturing treatment.

For the various fracturing fluids and adjustments of variouscharacteristics of the fracturing fluid discussed herein for theformation of pillars, the proppant in a given fracturing fluid atdifferent rheology should aggregate at different places in the fracture.Also, for stability of pillars the proppant should agglomerate. Onetechnique of agglomeration is to make proppant adequately hydrophobic sothat the proppant agglomerates and then fuses with pressure andtemperature from the subterranean formation. Some resins as proppantcoating can be used to promote that proppant agglomerate and form stablepillars. Sticky resin or tackifier as proppant coating can be used inimplementations to agglomerate proppant in the proppant pillar.

For a given fracturing fluid, proppant in one rheology fluid may formone pillar and proppant in other rheology fluid may form another pillarat different depth due to different settling rate/velocity. For pillarsto form, the fracturing fluid should suspend the proppant during theduration of conveyance and then when the fracture closes, the fractureclosing may generally maintain pillars in place throughout the fracture.Settling of the proppant to the bottom should generally be avoidedduring the pumping. To prevent or reduce complete settling, degradablematerials can be added to the fracturing fluid (e.g., any of thefracturing fluids discussed herein) as sacrificial material to keepproppant pillars suspended in the fracture before the formation closes.In some cases, fibers can be utilized as the degradable material. Thisimplementation of degradable materials is application for the fracturingfluids (e.g., VES-based fracturing fluid, foam fracturing fluid, etc.)presented in this disclosure.

As mentioned, pillar fracturing may be implemented through controlledfoam quality and utilizing advanced proppant and sand coating. Pillarfracturing can also be achieved with non-foam fracturing fluid, such aswith VES-based fracturing fluid through controlled application ofconcentrations in the VES fracturing fluid of the VES, brine,microparticles, and nanoparticles. The techniques may give extendedpropped half-length, substantially solids-free hydrocarbon production,and relatively rapid recovery of pumped fluids. This may enhance theproppant transport capacity deeper into the fracture resulting in longerconductive propped half-length. The recovery of the pumped fluid (e.g.,fracturing fluid) as flowback may be more rapid due to betterconductivity provided by the segregated accumulation of proppant(proppant pillars) compared to conventional distribution of proppant inthe fractures. Moreover, the density of the proppant coated withnanocomposite resin or density of the proppant coated with ceramichaving CMC can be lower than density of high strength proppant (HSP) andintermediate strength proppant (ISP) while giving advantage of increasedcrush resistance and conductivity. Conductivity of the proppant may beas retained permeability of the proppant at width of proppant. In pillarfracturing, the total conductivity is improved (e.g., to include theflow conductivity between the pillars and within the pillars). Theproduced-hydrocarbon flow conductivity includes flow in regions betweenthe pillars of proppant, between proppant in a proppant pillar orproppant pack, and between proppant and the formation, and so on.Further, embodiments may resolve the condensation banking problem due toapplication of nano-functionalized coated proppant that reduces theinterfacial tension in the proppant pack in the pillars and prevents orreduces condensate and water blockage in the near-wellbore area.Condensate banking may be the buildup of condensate around the wellborethat reduces relative permeability and therefore reduces gas production.

As indicated, conventionally the conductivity of proppant may be definedas retained permeability of the proppant multiplied by the width ofproppant. Yet, in cases of pillar fracturing, the total conductivity isincreased and may generally include the flow conductivity between thepillars and within the pillars. Typically, conventional resin coatingreduces permeability when compared to the proppant substrate. Theadvance coating technology may be aimed to maintain or enhancepermeability than the substrate or to limit permeability reduction whencompared to the conventional resins. Resin coated proppant may havelower conductivity than bare proppant. Yet, under stress the proppantcrushes and generates fines. These fines travel and block the pore spacebetween proppant and reduce permeability and thus conductivity. Forinstance, 5% of fines can reduce conductivity by more than 70%. Resincoated proppant may maintain the crushed fines in the sack and limittravel in proppant pack and not accumulating in pore space. Thus,conductivity of resin coated proppant can be higher. In implementations,conductivity may come from the intestinal spaces between the proppantparticles and generally not the porosity of proppant particles.

As discussed, for a particular hydraulic-fracturing or pillar-fracturingapplication, the pulsing or intermittent adjusting of a fracturing-fluidproperty may refer to a single-type fracturing fluid. Inimplementations, the pulsing or intermittent adjusting generally doesnot refer to alternating two types of fracturing fluid. Instead, aproperty, characteristic, attribute, or quality of the particularfracturing fluid is intermittently adjusted or pulsed to form thepillars of proppant in the fractures for a given application. Inimplementations, the intermittent adjustments can be made online,including on-the-fly, as the fracturing fluid is being pumped into thewellbore. Examples of the single type of fracturing fluid for a givenpillar-fracturing job include foam fracturing fluid, VES-basedfracturing fluid (water-based and can be polymer free), water-basedpolymer fracturing fluid, oil-based fracturing fluid, etc.

For applications of foam fracturing fluid, the foam fracturing-fluidproperty or characteristic intermittently adjusted (altered) to form thepillars may be viscosity or foam stability, or both. The FQ may affectthe viscosity. Further, the concentration of foaming surfactant in thefoam fracturing fluid may affect the foam stability. Indeed, foamingsurfactant may be added to the foam fracturing fluid to promote foamstability. The FQ and foaming-surfactant concentration may affect foamstability (and viscosity) and thus may affect proppant suspension andsettling velocity (units of distance per time). Implementing alternatingvalues for FQ or foaming-surfactant concentration in the foam fracturingfluid conveying the proppant may alternate between greater ability andless ability of the foam fracturing fluid to suspend and transportproppant. Thus, implementing alternating FQ values or alternatingfoaming-surfactant concentration values during the conveying of theproppant by the foam fracturing fluid into the fractures may formpillars of the proppant in the fractures.

As mentioned, the FQ may affect viscosity. The intermittent adjustmentsmay repeatedly cycle through (a) the foam fracturing fluid having afirst FQ and (b) the foam fracturing fluid having a second FQ differentthan the first FQ. This in turn may form pillars because the proppantsuspension or settling velocity at the first FQ may be different thanthe proppant suspension or settling velocity at the second FQ.

The second FQ is different than the first FQ for the pillars to form.The difference may vary well-by-well based on laboratory tests at bottomhole static and cool down conditions, surface and bottom hole pressurelimitations, type of liquid phase and remaining pumping time, etc.Moreover, the intermittent adjustment may be made with more than two FQvalues to maintain effective rheology contrast (e.g., based on dynamiccondition during pumping, such as formation cooldown and remainingpumping time) to form pillars of proppant. In implementations, theamount of proppant in the pumped fracturing fluid (proppantconcentration in the pumped fracturing fluid) may be maintainedgenerally constant during the varying of FQ.

The FQ may be adjusted by adding gas (e.g., N2, CO2, etc.) or liquid(e.g., water/brine) to the foam fracturing fluid. The FQ of the foamfracturing fluid can be a property or characteristic of the foamfracturing fluid conveying the proppant that is intermittently adjusted(e.g., with alternating values) to affect proppant suspension to formproppant pillars in the fractures. The alternating between FQ values maygive segregation in the distribution of the proppant in the fractures.

As indicated, concentration of foaming surfactant in the foam fracturingfluid may affect the foam stability of foam fracturing fluid. The foamstability of the foam fracturing fluid may affect the proppantsuspension and settling velocity of the foam fracturing fluid. To formpillars of proppant in the fractures, the intermittent adjustments tothe foam fracturing fluid conveying the proppant may repeatedly cyclethrough (a) a first concentration of foaming surfactant and (b) a secondconcentration of foaming surfactant different than the firstconcentration. This may form pillars because the proppant suspension orsettling velocity at the first concentration of foaming surfactant maybe different than the proppant suspension or settling velocity at thesecond concentration of foaming surfactant. The foaming-surfactantconcentration in the foam fracturing fluid can be a characteristic ofthe foam fracturing fluid conveying the proppant that is intermittentlyadjusted (e.g., with alternating values) to affect proppant suspensionto form proppant pillars in the fractures. The alternating betweenfoaming-surfactant concentration values may segregate accumulations ofproppant in the fractures. The intermittent adjustments may implementmore than two concentrations of foaming surfactant to give rheologycontrast in the fracturing fluid to form pillars of proppant.Considerations may include, for example, dynamic condition duringpumping, such as formation cooldown and remaining pumping time.

The foam fracturing fluid may include foaming surfactant at specifiedconcentrations and FQ at specified percentages for foam stability totransport proppant along the hydraulic fractures. As mentioned, thepillars can be formed by varying FQ or foaming-surfactant concentration,or both. Stability and half-life of the foam can impact the formation ofpillars. Foam that can last for longer time and have tunable FQ orviscosity may be beneficial. The stability of foam fracturing fluid maybe increased by addition of nanoparticles or microparticles, or both. Toform pillars of proppant in the fractures, the intermittent adjustmentsto the foam fracturing fluid conveying the proppant may repeatedly cyclethrough (a) a first concentration of nanoparticles (or microparticles)and (b) a second concentration of nanoparticles (or microparticles)different than the first concentration. The intermittent adjustments mayimplement more than two concentrations of the nanoparticles (ormicroparticles) in the fracturing fluid to give rheology contrast in thefracturing fluid to form pillars of proppant. The number of particleconcentrations applied in the cycling may be based in part on thedynamic condition during pumping of the fracturing fluid, such asformation cooldown and remaining pumping time.

The concentration of nanoparticles (or microparticles) in the foamfracturing fluid can be a characteristic of the foam fracturing fluidconveying the proppant that is intermittently adjusted (e.g., withalternating values) to affect proppant suspension to form proppantpillars in the fractures. The alternating between the particlesconcentration values may provide for accumulations of proppant that aresegregated in the fractures. The condition of the foam may beintermittently adjusted to segregate distribution of the conveyedproppant in the fractures to form pillars by varying the particleconcentration, gas volume (FQ), and foaming surfactant (foamer)concentration. Varying or pulsing of FQ may be, for example, betweenzero (no gas phase, FQ=0%) and a specific or non-zero value (e.g.,FQ=55%). The amount of proppant utilized may be, for example, 0% to 50%less than the amount employed in traditional fracturing. The lessproppant utilized may avoid fully filling the fracture so to formpillars having adjacent open-channel space. Therefore, in embodiments,the amount of fluid pumped will be the same as in traditional fracturingbut amount of proppant used will be 0-50% lower.

For applications of VES-based fracturing fluid, the VES fracturing-fluidproperty intermittently adjusted to form the pillars may beviscoelasticity or viscosity. The viscoelasticity or viscosity mayaffect the settling velocity. Implementing alternating values forviscosity (or viscoelasticity) of the VES fracturing fluid may alternatethe proppant suspension and proppant settling velocity of the VESfracturing fluid. This controlled varying of viscosity in sequences maysegregate proppant as delivered and distributed in the fractures. Thus,implementing alternating viscosity (or viscoelasticity) of the VESfracturing fluid during the conveying of the proppant by the VESfracturing fluid into the fractures may form pillars of the proppant inthe fractures. The intermittent adjustments may repeatedly cycle through(a) a first condition of the VES fracturing fluid having a firstviscosity and (b) a second condition of the VES fracturing fluid havinga second viscosity different than the first viscosity. This in turn mayform pillars because the proppant suspension or settling velocity at thefirst viscosity may be different than the proppant suspension orsettling velocity at the second viscosity. In these implementations, thesecond viscosity is different than the first viscosity for the pillarsto form. The magnitude of the different may well-by-well based, forexample, on laboratory tests (e.g., rheology profile determined by HPHTrheometer, fluids leak off, etc.) at bottom hole static and cool downconditions, surface and bottom hole pressure limitations, and remainingpumping time, etc. In addition, viscosity should generally be abovescreenout value. Fluids rheology profiles (based on static and dynamicconditions) may be entered into the fracture simulator. The viscositycontrast may be improved or optimized considering variables such as pumprate, fracturing fluid efficiency, physical properties of proppants,stage proppant concentration, pumping time, fracture closure time, andso forth.

The viscosity of the VES fracturing fluid conveying the proppant can bechanged by changing the VES concentration in the VES fracturing fluid.Increasing VES concentration will generally increase the viscosity.Decreasing the VES concentration will generally decrease the viscosity.The intermittent adjustments may repeatedly cycle through a firstconcentration of VES in the VES fracturing fluid and a secondconcentration of the VES in the VES fracturing fluid that is differentthan the first concentration. Such may form pillars in the fractures.The VES concentration in the VES fracturing fluid can be acharacteristic of the VES fracturing fluid that can be intermittentlyadjusted (e.g., with alternating values) to affect proppant suspensionto form proppant pillars in the fractures. The alternating between VESconcentration values may accumulate proppant in regions of the fracturesand provide separation between the accumulations.

Viscosity of the VES fracturing fluid conveying the proppant can also beaffected by addition of microparticles or nanoparticles to the VESfracturing fluid. Increasing concentration of microparticles ornanoparticles may generally increase the viscosity of the VES fracturingfluid. Decreasing the concentration of the microparticles ornanoparticles may generally decrease the viscosity. The intermittentadjustments (pulsing) may repeatedly cycle through a first concentrationof microparticles or nanoparticles in the VES fracturing fluid and asecond concentration of the microparticles or nanoparticles in the VESfracturing fluid that is different than the first concentration. Thismay facilitate the forming of pillars of proppant in the fractures. Asmentioned, the intermittent adjustments may be made with more than twoconcentrations of microparticles or nanoparticles to maintain optimum orbeneficial rheology contrast (e.g., based on dynamic conditions duringpumping such as formation cooldown and remaining pumping time, and thelike) to form pillars of proppant. The concentration of microparticlesor nanoparticles in the VES fracturing fluid can be a characteristic ofthe VES fracturing fluid that can be intermittently adjusted (e.g.,alternating values for the concentration) to affect proppant suspensionto form proppant pillars in the fractures. The alternating betweenparticle concentration values may give segregated distribution ofproppant in the fractures to form the pillars.

The viscosity of the VES fracturing fluid conveying the proppant can bealtered by changing brine concentration (salinity) of the brineincorporate into the VES fracturing fluid. Increasing the brine salinityto increase salt concentration in the VES fracturing fluid may generallyincrease the viscosity of the VES fracturing fluid. Decreasing the brinesalinity to decrease the salt concentration in the VES fracturing fluidmay generally decrease the viscosity. Intermittent adjustments mayrepeatedly cycle through a first concentration of salt in the VESfracturing fluid and a second concentration of salt in the VESfracturing fluid that is different than the first concentration. Thismay form pillars in the fractures. The salt concentration in the VESfracturing fluid can be a property or characteristic of the VESfracturing fluid that can be intermittently adjusted (e.g., havingalternating values of salt concentration) to affect proppant suspensionto form proppant pillars in the fractures.

Furthermore, the intermittent adjustments may alternate betweendifferent types of salt to affect viscosity to promote segregateddistribution of proppant in the fractures to form pillars of proppant inthe fractures. For instance, a first type of salt may be a monovalentsalt (e.g., giving monovalent ions such as sodium Na ions or potassium Kions) and the second type of salt may be multivalent salt (e.g., givingmultivalent ions such as calcium Ca+2 ions). In some cases at the samesalt concentration in the VES fracturing fluid, multivalent Ca+2 ionsmay give greater viscosity of the VES fracturing fluid than monovalentNa or K ions. The VES salt type in the VES fracturing fluid can be acharacteristic of the VES fracturing fluid that can be intermittentlyadjusted (alternated) to affect proppant suspension to form proppantpillars in the fractures.

As indicated, for the formation of pillars, the proppant in the lowerviscosity and higher viscosity should aggregate at different places.Moreover, for stability of pillars, the proppant should agglomerate. Onetechnique of agglomeration is to make proppant hydrophobic enough sothat the proppant agglomerate via hydrophobic interaction and then fuseat pressure and temperature of the subterranean formation. The proppantmay have a hydrophobic coating. The proppant hydrophobic coating maybind together proppant as an agglomerate. Further, some resins can beutilized to make proppant agglomerate and form stable pillars. Stickyresins can be used to agglomerate proppant in a proppant pillar.

Furthermore, proppant in one viscosity fluid may form one pillar andproppant in another viscosity fluid may form another pillar at adifferent depth (e.g., in a vertical fracture) due to different settlingrate/velocity. For pillars to form the fluid should suspend the proppantduring the duration of fracturing and then when the fracture closes, thefracture closing may generally keep pillars in place throughout thefracture. It may be desirable that the proppant not settle to the bottomduring the pumping. To prevent or reduce complete settling, suspendingagents (e.g., degradable materials) can be added to the fluid assacrificial material to keep proppant pillars suspended in the fracturebefore the formation closes. In some cases, fibers can be used as thedegradable material. The degradable material may be in the form of fiberor particles. This implementation of degradable materials is applicablefor both VES fracturing fluid and foam fracturing fluid, and otherfracturing fluids.

The intermittent adjustments to the VES-based fracturing fluid can be toalternate between (a) addition of a crosslinker and (b) no addition of acrosslinker. The VES fracturing fluid can have a polymer component withpresence of the crosslinker. The crosslinker in the VES-based fluid cangive stable fluid in viscosity. The varying of the crosslinkerconcentration can give different quality of the VES fluid. An example ofthe VES crosslinker is dicarboxylic acids (e.g., tartaric acid) whichcrosslink a headgroup (e.g., amine headgroup) of VES surfactants Theintermittent adjustments may repeatedly cycle through a firstconcentration of crosslinker in the VES fracturing fluid and a secondconcentration of the crosslinker in the VES fracturing fluid that isdifferent than the first concentration. Such may form pillars ofproppant in the fractures due to the effect of the changing viscosity ofthe VES fracturing fluid on the conveyed proppant distribution in thefractures. The alternating between crosslinker concentration values maygive segregated distribution of proppant in the fractures to form thepillars. Often, the intermittent adjustments may be made with more thantwo concentrations of crosslinker to maintain optimum or beneficialrheology contrast (based on dynamic conditions during pumping such asformation cooldown, remaining pumping time, etc.) to form pillars ofproppant.

Oil-based fracturing fluid is a non-foam fracturing fluid. The oil-basedfracturing fluid can convey proppant to form pillars. The oil-basedfracturing fluid may be a viscous gelled oil system. The oil gels of theoil-based fracturing fluid can be formed, for example, by phosphonateesters and crosslinked by metal ions such as iron. Proppant suspensionor setting rate can be altered to form pillars by varying the quality ofthe oil gel, such as by intermittently adjusting the concentration ofthe crosslinker metal ions. The periodic adjustments may repeatedlycycle through a first concentration of crosslinker metal ions in theoil-based fracturing fluid and a second concentration of the crosslinkermetal ions in the oil-based fracturing fluid that is different than thefirst concentration. Such may form pillars of proppant in the fractures.Three or more values for concentration of the crosslinker metal ions maybe implemented in the cycling adjustments. The concentration ofcrosslinker metal ions may be a characteristic of the oil-basedfracturing fluid that can be intermittently adjusted (pulsed) to formpillars of proppant in the fractures in the subterranean formation.Proppant pulsing with the emulsion fracturing fluid can also beadditionally performed to form the pillars, such in combination with theaforementioned techniques.

Emulsion (emulsified) fracturing fluid is a non-foam fracturing fluidthat can perform hydraulic fracturing and can convey proppant throughthe wellbore into the hydraulic fractures in the subterranean formationto form pillars of proppant in the fractures. The emulsion fracturingfluid can include a mixture of viscosified water and oil. The oil maybe, for example, mineral oil. The emulsified fluid system can bestabilized with emulsifying surfactant (emulsifier), microparticles, ornanoparticles, or any combinations thereof. The emulsified fluid systemcan have high viscosity and desired proppant suspension capacity. Theemulsion fracturing fluid can provide for fluids-loss control andgenerally less formation damage. The quality and proppant suspension ofthe emulsion fracturing fluid may be impacted by: (a) the concentrationof the emulsifying surfactant (emulsifier) in the emulsion fracturingfluid; (b) the ratio (e.g., mass ratio or volume ratio) of water to oilin the emulsion fracturing fluid; (c) the concentration ofmicroparticles or nanoparticles, or both, in the emulsion fracturingfluid; and (d) the salt concentration or brine concentration in theemulsion fracturing fluid. These characteristics (a), (b), (c), and (d)of the emulsion fracturing fluid can be intermittently varied to formpillars in the fractures. Pillars can be created through controlledproppant suspension and settling velocity with at least one or more ofthe following actions: (1) varying ratio of the viscosified water andoil; (2) varying concentration of the emulsifier; (3) varyingconcentration of microparticles and/or nanoparticles; and (4) varyingsalt concentration or brine concentration. The salt concentration orbrine concentration may affect viscosity of the water and thus affectviscosity of the emulsion. Also, the intermittent adjustments mayinvolve varying concentration of internal phase in the emulsionfracturing fluid. The greater the internal-phase concentration,generally the greater the viscosity of emulsion. Also, the viscosity maydepend on emulsion droplet size. Smaller size droplet may give moreviscosity than bigger droplet size. Invert emulsion can gives moreviscosity for proppant suspension but also result in more friction(greater pressure drop) when pumping the fracturing fluid through pipes.

A foamed-emulsion fracturing fluid may be employed in the hydraulicfracturing and to convey proppant into the fractures to form pillars ofproppant. To form the foamed emulsion, oil (e.g., mineral oil) and gas(e.g., N2 or CO2) may be dispersed in water. In the foamed emulsion, thewater may be the external or continuous phase. The oil and gas may eachbe respective internal or discontinuous phases in or dispersed in thewater that is the continuous phase. Thus, the internal phase of thefoamed emulsion can be two respective internal phases including an oilphase and a gas phase (e.g., CO2 or N2). Surfactant in thefoamed-emulsion fracturing fluid may facilitate formation of fracturingfluid as foamed-emulsion with the water as the continuous phase.Characteristics or variables of the foamed-emulsion fracturing fluidthat may be intermittently varied to form the pillars may include ratioof water and oil, ratio of water and gas, FQ, and concentration ofsurfactant.

FIG. 1 is a well site 100 having a wellbore 102 formed through the Earthsurface 104 into a subterranean formation 106 in the Earth crust. Thesubterranean formation 106 may be labeled as a geological formation, areservoir formation, a reservoir, a rock formation, or a hydrocarbonformation, and the like. The subterranean formation 106 may be aconventional or unconventional formation to be subjected to hydraulicfracturing and in which pillars of proppant are formed in the hydraulicfractures. Thus, pillar fracturing may be performed.

The wellbore 102 can be vertical, horizontal, or deviated. The wellbore102 can be openhole but is generally a cased wellbore. The annulusbetween the casing and the formation 106 may be cemented. Perforationsmay be formed through the casing and cement into the formation 106. Theperforations may allow both for flow of fracturing fluid and proppantinto the subterranean formation 106 and for flow of produced hydrocarbonfrom the subterranean formation 106 into the wellbore 102. The surfaceequipment 108 may also include equipment to support the hydraulicfracturing.

The well site 100 may have a hydraulic fracturing system including asource 110 of fracturing fluid 112 at the Earth surface 104 near oradjacent the wellbore 102. The source 110 may include one or morevessels holding the fracturing fluid 112. The fracturing fluid 112 maybe held in vessels or containers on ground, on a vehicle (for example,truck or trailer), or skid-mounted. The fracturing fluid 110 may be, forexample, water-based or oil-based.

The hydraulic fracturing system at the well site 100 may include motivedevices such as one or more pumps 114 to pump (inject) the fracturingfluid 112 (with or without proppant) through the wellbore 102 into thesubterranean formation 106. The pumps 114 may be, for example, positivedisplacement pumps and arranged in series or parallel. Again, thewellbore 102 may be a cemented cased wellbore and have perforations forthe fracturing fluid 112 to flow (injected) into the formation 106. Insome implementations, the speed of the pumps 114 may be controlled togive desired flow rate of the fracturing fluid 112. The system mayinclude a control device to modulate or maintain the flow of fracturingfluid 112 into the wellbore 102 for the hydraulic fracturing and formingthe pillars. The control device may be, for example, a control valve(s).In certain implementations, as indicated, the control device may be thepump(s) 114 as a metering pump in which speed of the pump 114 iscontrolled to give the desired or specified flow rate of the fracturingfluid 112. The set point of the control device may be manually set ordriven by a control system, such as the control system 116.

The pump 114 may be operationally coupled to the source 110 to providethe fracturing fluid 112 through the wellbore 102 into the subterraneanformation 106 to hydraulically fracture the subterranean formation 106to generate fractures in the subterranean formation 106 and form pillarsof proppant in the fractures. The pump 114 may pump the fracturing fluid112 conveying proppant into the generated fractures to form the pillarsof proppant in the fractures. In some examples, the fracturing fluid 112may be initially pumped without proppant (a clean rate) during abeginning portion of the hydraulic fracturing, and subsequently pumpedwith proppant (a slurry rate) in a subsequent portion of the hydraulicfracturing to form the pillars in the fractures. The fracturing fluid112 without proppant may hydraulically fracture the subterraneanformation 106. The fracture fluid 112 with the proppant mayhydraulically fracture the formation 106 and increase width of hydraulicfractures generated by the fracturing fluid 112 without proppant.

For some embodiments, the fracturing fluid 112 in the source 110 vesselmay have all components of the fracturing fluid 112. In otherembodiments, not all components of the fracturing fluid 112 are includedin the source 110 vessel. In certain embodiments, some components of thefracturing fluid 112 may be added to the source 108 vessel near or atthe time (or during) the pumping of the fracturing fluid 112 into thewellbore 102 for the hydraulic fracturing. Concentrations of componentsin the fracturing fluid 112 may be adjusted during the hydraulicfracturing and pillar formation. In embodiments, at least one componentof the fracturing fluid 112 is added to the conduit conveying thefracturing fluid 112 either on the suction side of the pump 114 ordischarge side of the pump 114, or both, as the fracturing fluid 112 isbeing pumped into the wellbore 102.

The fracturing fluid 112 may be prepared (formulated and mixed) offsiteprior to disposition of the fracturing fluid 112 into the source 110vessel at the well site 100. A portion (some components) of thefracturing fluid 112 may be mixed offsite and disposed into the source110 vessel and the remaining portion (remaining components) of thefracturing fluid 112 added to the source 110 vessel or to a conduitconveying the fracturing fluid 112. The fracturing fluid 112 may beprepared onsite with components added to (and batch mixed in) the source100 vessel. Components may be added online to the source 110 vessel orto a conduit conveying the fracturing fluid 112 during the hydraulicfracturing and conveying of proppant.

The illustrated embodiment includes three addition points 118, 120, and122 for introducing components to the fracturing fluid 112. Multiplecomponents may added at a respective addition point. Examples ofcomponents added to the fracturing fluid 112 via one or more of theaddition points 118, 120, and 122 may include brine, brine substitute,surfactant, gas, N2 gas, CO2, water, oil (e.g., mineral oil),microparticles, nanoparticles, crosslinker (e.g., giving metal ions),breaker, biocide, and so on. Brine or brine substitute may typically beadded to the source 110 vessel for batch mixing. Brine substitute istypically liquid-organic clay stabilizer for temporary or permanent claystabilization. The brine substitute in VES fluid may have dual role inclay sensitive formation including clay control and rheology control forthe VES fluid. These clay inhibitors in the brine substitute areutilized in place of KCl or other salts of typical brine. Some examplesof the clay inhibitors include choline chloride, tetramethyl ammoniumchloride, 1,6-hexamethylenediamine hydrochloride, and the like. Examplesof surfactant include VES, foaming surfactant (foamer), or emulsifyingsurfactant (emulsifier). If CO2 is added, the CO2 may be added insupercritical condition. For CO2 or N2, the rig up may be separated fromthe other liquid phase. CO2 or N2 may be mixed with the liquid stream,for example, at the wellhead. Examples of the fracturing fluid 110include liquid part foam fracturing fluid, VES-based fracturing fluid,emulsion fracturing fluid, or oil-based fracturing fluid, and so on.

The first addition point 118 is to the source 110 vessel holding thefracturing fluid 112. Components added to the fracturing fluid 112 atsource 110 may be batch mixed with the fracturing fluid 112 in thevessel in some implementations. As mentioned, brine is an example of acomponent that may typically be added to the source 110 vessel. Thesecond addition point 120 is to fracturing fluid 112 flowing through thesuction conduit of the pump 114. Proppant is an example of a componentthat may typically be added to the suction conduit of the pump 114. Thethird addition point 122 is to fracturing fluid 112 flowing through thedischarge conduit of the pump 114. An example of a component that may beinjected to the discharge conduit of the pump 114 is surfactant. Eachaddition point may include a respective control device 124, 126, and 128for adjusting the component stream being added to the fracturing fluid112. The adjustment may be to adjust the addition rate (flow rate) ofthe component stream and/or component concentration in the componentstream. Each addition point may include multiple conduits and controldevices for adding multiple components separately.

The hydraulic fracturing system at the well site 100 may have a sourceof proppant, which can include railcars, hoppers, containers, or binshaving the proppant. Proppant may be segregated by type or mesh size(particle size). The proppant can be, for example, sand or ceramicproppants. The proppant may have advanced coatings. The source ofproppant may be at the Earth surface 104 near or adjacent to the sourceof fracturing fluid 110. The proppant may be added to the fracturingfluid 112 such that the fracturing fluid 112 includes the proppant. Insome implementations, the proppant may be added (for example, viagravity) to a conduit conveying the fracturing fluid 112, such as at asuction of a fracturing fluid pump 114. As mentioned, the proppant maybe added (e.g., via gravity) to the suction conduit of the pump 114 viathe control device 126. The control device 126 may include a feeder orblender that receives proppant from the proppant source and dischargesthe proppant into pump 114 suction conduit conveying the fracturingfluid 112. Different proppant sizes may be utilized during the job toform pillars. The smaller proppants will generally have the lowersettling velocity than the larger proppant particles. This can be reliedon to make different pillars without changing the rheology of thefracturing fluid in some embodiments. Again, these proppant particlescan be coated for agglomeration. The coating can be resin or tackifyingmaterial, and the like.

The fracturing fluid 112 may be a slurry having the solid proppant. Thepump 114 discharge flow rates (frac rates) may include a slurry ratewhich may be a flow rate of the fracturing fluid 112 as slurry havingproppant. The pump 114 discharge flow rates (frac rates) may include aclean rate which is a flow rate of fracturing fluid 112 withoutproppant. In particular implementations, the fracturing systemparameters adjusted may include at least pump(s) 114 rate, proppantconcentration in the fracturing fluid 112, component addition rate(e.g., at addition points 118, 120, and 122), and componentconcentration in the fracturing fluid 112. Fracturing operations can bemanual or guided with controllers.

The well site 100 may include a control system 116 that supports or is apart of the hydraulic fracturing system. The control system 116 includesa processor 130 and memory 132 storing code 134 (e.g., logic,instructions, etc.) executed by the processor 130 to performcalculations and direct operations at the well site 100. The processor130 may be one or more processors and each processor may have one ormore cores. The hardware processor(s) 130 may include a microprocessor,a central processing unit (CPU), a graphic processing unit (GPU), acontroller card, or other circuitry. The memory 132 may include volatilememory, such as cache and random access memory (RAM). The memory 132 mayinclude nonvolatile memory, such as a hard drive, solid-state drive, andread-only memory (ROM). The memory 132 may include firmware. The controlsystem 116 may include a desktop computer, laptop computer, computerserver, programmable logic controller (PLC), distributed computingsystem (DSC), controllers, actuators, control cards, an instrument oranalyzer, and a user interface. In operation, the control system 116 mayfacilitate processes at the well site 100 and including to directoperation of aspects of the hydraulic fracturing system. The controlsystem 116 may be communicatively coupled to a remote computing systemthat performs calculations and provides direction. The control system116 may receive user input or remote-computer input that specifies theset points of the control devices 124, 126, and 128 or other controldevices in the hydraulic fracturing system.

The control system 116 may specify the set point of the control devices124, 126, and 128 for component additions to the fracturing fluid at theaddition points 118, 120, and 122, respectively. The set points (andassociated time intervals for intermittently changing between setpoints) may be manually input by a user or human operator into thecontrol system 116. In some implementations, the control system 116 maycalculate or otherwise determine the set point of the control devices124, 126, and 128. The determination may be based at least in part oncalculations (e.g., mass balance calculations), operating conditions ofthe hydraulic fracturing, and information (or feedback) from thehydraulic fracturing system. The control system 116 may include localcontrollers distributed at the well site 100 that perform thesefunctions independent of central control by the control system 116.

Whether based on human input or as determined by the control system 116,the control system 116 may intermittently adjust a characteristic(property, attribute, etc.) of the fracturing fluid 112 conveying theproppant to form pillars of proppant in the fractures. Thecharacteristic adjusted may be tiered in that an overall attribute suchas viscosity or proppant suspension is adjusted by adjustingconcentration or addition rate of a component of the fracturing fluid112. The control system 116 intermittently adjusting the characteristicmay involve the control system 116 adjusting the characteristic at afrequency of a specified time interval to give pillar formation. Thetime interval as specified and applied may be, for example, in the rangeof 1 minute to 2 hours, or in the range of 2 minutes to 100 minutes.Again, the time interval may be specified (input) to the control system116. The set points for values of (or associated with) thecharacteristic may be specified (input) to the control system 116 toprovide for pillar formation. The control system 116 may include acontroller (e.g., control card or other circuitry) to receive the inputsand drive control devices (e.g., 124, 126, and/or 128) to make theintermittent (recurrent, alternating, periodic, cyclical, repeatedcycle, etc.) adjustments of the characteristic at the time interval toform the pillars. This controller may be encompassed by the processor130 and the code 134 as executed by the processor 130. In operation, thecontrol system 116 may alternate between (repeatedly cycle through) afirst value of the characteristic and a second value of characteristicthat is different than the first value. The control may alternatebetween more than two values of the characteristic.

In some embodiments, the control system 116 alters viscosity of thefracturing fluid 112 to provide for segregation of proppant in thefractures to form the pillars. In some examples, surfactant (e.g., VES,emulsifying surfactant, foaming surfactant, etc.) increases viscosity ofthe fracturing fluid conveying the proppant. Thus, the characteristicmay be concentration of the surfactant in the fracturing fluid 112 oraddition rate of the surfactant to the fracturing fluid 112. A firstconcentration of surfactant in the fracturing fluid 112 may give a firstviscosity value of the fracturing fluid 112, and a second concentration(lower than the first concentration) of surfactant may give a secondviscosity value of the fracturing fluid 112 that is less than the firstviscosity value. The intermittent adjustments may be to alternatebetween the first concentration and the second concentration. Theintermittent adjustments may be to alternate between a first additionrate of the surfactant that gives the first concentration and a secondaddition rate of the surfactant less than the first addition rate togive the second concentration. The addition rate of the surfactant maybe controlled by a local controller via the respective control device124, 126, or 128, or controlled by the control system 116 via therespective control device 124, 126, or 128. In some examples, thesurfactant may be added on-the-fly at the addition point 122 to thedischarge conduit of the pump 114 as the pump 114 is pumping thefracturing fluid 112 with the proppant. The control device 124 (e.g.,flow control valve) may adjust the addition rate (e.g., mass flow rateor volume flow rate) of the surfactant to the fracturing fluid 112. Thecontrol system 116 controller may adjust the set point of the flowcontroller (FC) of the flow control valve that is the control device124. The inputs to the control system 116 may be the first and secondconcentrations or the first and second addition rates. To form thepillars, the control system 116 may alternate between (repeatedly cyclethrough) the first concentration or addition rate and the secondconcentration or addition rate is different than the first concentrationor addition rate. A third concentration (or third addition rate), fourthconcentration (or fourth addition rate), etc. may be included in thecycle. This example control scheme with respect to surfactant may applyto other components of the fracturing fluid 112, such as microparticlesor nanoparticles, oil (e.g., mineral oil), water, crosslinker, brine,brine substitute, and so on.

The brine or brine substitute may be more typically added at additionpoints 118 or 120. To affect the rheology or viscosity of the fracturingfluid 112 (e.g., to affect proppant suspension capacity) to formpillars, the intermittent adjustments may involve cycling throughdifferent values of the salinity of the brine and/or the amount of brineincorporated into the fracturing fluid 112. Adjusting the salinity ofthe brine (concentration of salt in the brine) are the amount of brineadded to the fracturing fluid 112 may give adjusted concentrations ofsalt in the fracturing fluid 112 to affect the viscosity of thefracturing fluid 112.

For instances of the fracturing fluid 112 as foam fracturing fluid, thecharacteristic intermittently adjusted may be volume concentration ofgas (e.g., N2) or supercritical CO2 in the fracturing fluid 112 oraddition rate of gas (e.g., N2) or supercritical CO2 (or water) to thefracturing fluid 112 to give an alternating FQ to drive pillar formationin the fractures. The N2 or CO2 may added to and mixed with the liquidportion of the fracturing fluid 112 at the wellhead. In someimplementations, the addition point 122 may be characterized as at thewellhead instead of on the discharge conduit of the pump 114. Theaddition rate of the N2 gas or supercritical CO2 (or water) may becontrolled by a local controller outside of or part of the controlsystem 116 via a control device, such as control device 128. The CO2 orN2 supply have dedicated and separate high pressure pumps, and highpressure treatment lines. Again, the liquid and the gas phases may bemixed at the wellhead. To form the pillars, the control system 116 orlocal control system may alternate between (repeatedly cycle through)the first FQ or N2/CO2 addition rates and the second FQ or N2/CO2addition rate that are different than the first FQ or N2/CO2 additionrates.

Furthermore, particles having a nominal diameter less than 1 millimeter(mm) may be added to the fracturing fluid 112 to increase viscosity ofthe fracturing fluid 112. Therefore, the concentration of theseparticles in the fracturing fluid 112 or the addition rate of theseparticles to the fracturing fluid 112 may be a characteristic that isintermittently adjusted. These particles may be microparticles ornanoparticles, or both. The control system 116 may alternate between(repeatedly cycle through) a first concentration of the particles and asecond concentration of the particles that is different than the firstconcentration. In some examples, one of the first or secondconcentrations may be zero (no microparticles or nanoparticles includedor added to the fracturing fluid 112). Moreover, the cycle may includemore than two concentrations or two addition rates. Lastly, it should benoted that adding larger particles may not increase viscosity but canincrease density of fracturing fluid 112 slurry. Also, with smallernanoparticles, the viscosity may increase via interaction of thenanoparticles with surfactant, VES, or polymer in the fracturing fluid.In embodiments, the addition of nanoparticles without the presence ofsurfactant or polymer may not increase viscosity. However, highconcentration of smaller particles (nanoparticles) in fracturing fluid112 fluid without surfactant or polymer may increase viscosity of thefracturing fluid 112 is some implementations.

For embodiments with the fracturing fluid 112 as an emulsion fracturingfluid that includes an emulsion of viscosified water and oil, the ratioof oil to water may affect viscosity or proppant suspension of thefracturing fluid 112. Therefore, this ratio may be a characteristic ofthe fracturing fluid 112 that is intermittently adjusted to provide forforming pillars of proppant in the fractures. In one example, alteringthe addition rate of oil or water added to the fracturing fluid 112 maybe implemented to intermittently adjust the oil-to-water ratio. Thecontrol system 116 may alternate between (repeatedly cycle through) afirst addition rate of oil or water and a second addition rate of oil orwater that is different than the first addition rate. The cycle mayinclude further addition rates of oil or water that are different thanthe first and second addition rates.

FIG. 2 are hydraulic fractures 200 having pillars 202 of proppant 204disposed in the fractures 200. The hydraulic fractures 200 areassociated with the wellbore 102 of FIG. 1 . The wellbore 102 isdepicted as a circular cross-section in FIG. 2 . In preparation for thehydraulic fracturing, a perforation 206 may be formed through thewellbore 102 wall into the subterranean formation 106. The wellbore 102may be a cemented cased wellbore. The perforation 206 may be formed toallow for flow of fracturing fluid 112 (with and without proppant 204)from the wellbore 102 into the formation 106.

In the illustrated implementation, the depicted hydraulic fractures 200include a main or primary fracture 208 and secondary fractures 210. Thefractures 208, 210 are hydraulically formed by injecting fracturingfluid 112 through the perforation 206 into the subterranean formation106. Of course, many more secondary fractures 210 than depicted may beformed with complex fracturing via the fracturing fluid 112. Thesecondary fractures 210 typically have a smaller fracture width than theprimary fracture 208. In this embodiment, the fracturing fluid 112conveys the proppant 204 into the primary fracture 208. The proppant 204may approach the fracture tip 212 of the primary fracture 208. Thedistance that the proppant 204 reaches toward the fracture tip 212 maydepend on characteristics of the fracturing fluid 112 and the particlesize of the proppant 204. The proppant 204 may be positioned in theprimary fracture 208 to maintain open the primary fracture 208. Thefracturing fluid 112 may convey the proppant 204 into secondaryfractures 210, as depicted, depending on particle size of the proppant204 and the fracture width of the secondary fractures 210. The proppant204 if present in a secondary fracture 210 may maintain open thesecondary fracture 210. The proppant 204 may include core proppanthaving a ceramic coating or resin coating, or both. The ceramic coatingcan include a CMC. The core proppant may be sand, metal, ceramic,organic particles, or other particles.

As mentioned, pillars 202 of proppant 204 may be formed in the fractures208, 210. The pillars 202 may be accumulations of proppant 204 that areadjacent to regions 214 (e.g., channels) in the fractures 208, 210 withlittle or no proppant 204. The pillars 202 of proppant 204 may be formedin the fractures 208, 210 by intermittently adjusting a characteristic(e.g., viscosity) of the fracturing fluid 112 conveying the proppant 204to affect proppant suspension of the fracturing fluid. When thefracturing fluid 112 has a lower viscosity or less proppant suspensioncapacity, the proppant 204 may settle from the fracturing fluid 112 inthe fractures 208, 210 at near wellbore. When the fracturing fluid 112has a higher viscosity or greater proppant suspension, the fracturingfluid 212 may carry the proppant 204 further into the fractures 208, 210to deposit the proppant 204. Thus, with varying the viscosity or relatedcharacteristic (or other characteristic) of the fracturing fluid 112,the distribution of the proppant 204 in the fractures 208, 210 may givethe accumulations or pillars 202 of the proppant 204. This segregatingor altering of the proppant distribution (final distribution) in thefractures 208, 210 can increase length and conductivity of the fractures208, 210. Moreover, the segregation can be promoted by redistributioninvolving pickup, re-suspend, transport, and resettle. The segregateddistribution forming the pillars 202 may be advanced with theintermittent adjustments to the fracturing fluid implemented as asequential or repeated cycling of values for the characteristic or foroperating parameters (e.g., component concentrations or addition rates)associated with the characteristic or attribute.

FIG. 3 is a method 300 of hydraulic fracturing a subterranean formationin the Earth crust, including to form pillars (accumulations) ofproppant in the generated fractures. The subterranean formation may alsobe labeled as a geological formation, reservoir formation, reservoir,rock formation, hydrocarbon formation, and the like. A hydraulicfracturing system may be disposed at the Earth surface near or adjacenta wellbore in the subterranean formation. The hydraulic fracturingsystem may include a source, e.g., including vessel(s), of fracturingfluid. The hydraulic fracturing system may also include a source ofproppant. In implementations, the proppant can be advanced proppant, forexample, in having advanced coatings.

At block 302, the method includes providing (e.g., pumping) thefracturing fluid through the wellbore into the subterranean formation.The fracturing fluid may be pumped from the Earth surface. Proppant maybe added to the fracturing fluid at the Earth surface. The wellbore maybe a cased wellbore having perforations for flow of the fracturing fluid(with and without proppant) into the subterranean formation. Thefracturing fluid may be, for example, foam fracturing fluid, VES-basedfracturing fluid, emulsion fracturing fluid, oil-based fracturing fluid,and other types of fracturing fluid. For a given hydraulic-fracturingjob, a single type of fracturing fluid may be utilized to form thepillars of proppant in fractures. In other words, alternating or pulsingdifferent types of fracturing fluid is not required to form the pillars.

At block 304, the method includes hydraulically fracturing thesubterranean formation with the fracturing fluid, thereby generatingfractures in the subterranean formation. In particular, the injection ofthe fracturing fluid by the pump through the wellbore perforations intothe subterranean formation may hydraulically fracture the subterraneanformation. The fracturing fluid may include additives, such as aviscosifier, friction reducer, clay inhibitor, buffer, scale inhibitor,flowback enhancer, corrosion inhibitor, or fluid loss agent, or anycombinations of these. The fluid may include suspending agent such asfibers of degradable materials, degradable materials, and tackifyingagents. The fracturing fluid may have a friction reducer to decreasefriction experienced by the fracturing fluid in the pumping of thefracturing fluid through the wellbore into the subterranean formation.The friction reducer may be, for example, an anionic copolymer. Theviscosifier (for example, a polysaccharide) increases viscosity of thefracturing fluid. One example of polysaccharide as a viscosifier is guaror guar gum (also called guaran), which is a galactomannanpolysaccharide. For multi-phase fracturing fluid, the viscosifier andfriction reducer may generally reside in the aqueous phase inimplementations.

At block 306, the method includes conveying proppant in the fracturingfluid through the wellbore into the fractures. In implementations, thefracturing fluid with the proppant may hydraulically fracture thesubterranean formation and increase width of hydraulic fractures alreadygenerated by the fracture fluid without proppant. The portion of thehydraulic-fracturing job in which the fracturing fluid has proppant maytransport the proppant into the hydraulic fractures via the fracturingfluid. The fracturing fluid, as pumped and injected, may distribute theproppant in the fractures.

At block 308, the method includes intermittently adjusting acharacteristic (e.g., attribute, property, component concentration,etc.) of the fracturing fluid conveying the proppant to form pillars ofproppant in the fractures. Thus, the method may include forming pillarsof proppant in the fractures by intermittently adjusting a property ofthe fracturing fluid conveying the proppant. In implementations, theaction of intermittently adjusting the characteristic does not includechanging type of fracturing fluid or pulsing different types offracturing fluid. In implementations, intermittently adjusting thecharacteristic or property includes adjusting the characteristic orproperty at a frequency at an interval in a range of 1 minutes to 2hours, or 2 minutes to 100 minutes. The characteristic may be proppantsuspension or the property viscosity, or both. The characteristic may besurfactant concentration (in the fracturing fluid) or brineconcentration (salt concentration in the brine incorporated into thefracturing fluid), or both. The characteristic may be concentration ofmicroparticles or concentration of nanoparticles, or both, in thefracturing fluid. In implementations, intermittently adjusting thecharacteristic of the fracturing fluid does not include pulsing proppantin the fracturing fluid. Further, again, without changing the rheologyof fluid but altering size of proppant injected can give differentsettling rates giving pillar formation. The particle diameter or meshsize of the proppant may be alternated between different values in theintermittent adjusting or cycling, with or without adjusting rheology ofthe fracturing fluid, to form pillars in certain implementations.

For the fracturing fluid including foam, the characteristic of thefracturing fluid adjusted may be associated with the foam. Thefracturing fluid may be foam fracturing fluid and the characteristic isa characteristic of the foam fracturing fluid. The characteristic orproperty may be at least one of foam stability or concentration of afoaming surfactant in the fracturing fluid. The action of intermittentlyadjusting the concentration of the foaming surfactant may involverepeatedly cycling through a first concentration of the foamingsurfactant in the foam fracturing fluid and a second concentration ofthe foaming surfactant in the foam fracturing fluid different than thefirst concentration. Additional concentrations (e.g., third, fourth,etc.) different than the first and second concentrations may beincorporated into the adjustment cycle. The characteristic or propertymay be FQ that can be, for example, in the range of 52% to 80% byvolume. The action of intermittently adjusting the FQ may involverepeatedly cycling through a first FQ of the foam fracturing fluid and asecond FQ of the foam fracturing fluid different than the first FQ.Additional FQ values (e.g., third, fourth, etc.) different than thefirst FQ and second FQ may be incorporated into the adjustment cycle.

As discussed and with respect to the method 300, the fracturing fluidmay be a non-foam fracturing fluid. For example, the fracturing fluidmay be VES-based fracturing fluid, and wherein the characteristic isconcentration of VES in the VES-based fracturing fluid. As described,the action of intermittently adjusting the concentration of the VES inthe VES-based fracturing fluid may involve repeatedly cycling through afirst concentration of the VES in the VES-based fracturing fluid and asecond concentration of the VES in the VES-based fracturing fluiddifferent than the first concentration. Additional values (e.g., third,fourth, etc.) for the concentration of the VES in the fracturing fluiddifferent than the first concentration and the second concentration maybe incorporated into the adjustment cycle. As also discussed, anothercharacteristic of VES-based fracturing fluid (or other fracturingfluids) that may be intermittently adjusted to form pillars of proppantin the fractures may include concentration of microparticles orconcentration of nanoparticles, or both, in the VES-based fracturingfluid.

As indicated for the fracturing fluid as foam fracturing fluid, thecontinuous phase may be water (aqueous phase). The discontinuous gasphase dispersed in the water may be an inert gas, nonpolar gas, inertnonpolar gas, gas generally immiscible with water, CO2, N2, ethane,propane, butane, or argon, or mixtures of these. The fracturing fluid asan emulsion fracturing fluid (mixture of two immiscible liquids) mayinclude an emulsified mixture of water (e.g., viscosified water) and oil(e.g., mineral oil). In the emulsion fracturing fluid, the water(aqueous phase) in the emulsion may be the continuous phase and the oilthe discontinuous phase, or the oil may be the continuous phase and thewater is the discontinuous phase. The surfactant may be an interfacialsurfactant. The surfactant, such as the emulsifying surfactant or thefoaming surfactant, may absorb to the boundary between two immisciblephases and facilitate formation of the emulsion or the foam. Surfactantmolecules may be amphiphilic in having a hydrophobic part (hydrophobictail) and a hydrophilic part (polar head group). The surfactant mayabsorb to the interface between a hydrophobic phase (for example, oil ornonpolar gas) and a hydrophilic phase (for example, water). At theinterface, the surfactant aligns so that the hydrophobic tail of thesurfactant molecule is in the nonpolar gas or oil, and the polar headgroup of the surfactant molecule is in the water. This may cause adecrease in surface or interfacial tensions. The hydrocarbon tail maybe, for example, a hydrocarbon, fluorocarbon, or siloxane. Surfactantsmay be classified as nonionic, anionic, cationic, or zwitterionic basedon the charge of the polar head group. A nonionic surfactant has a polarhead group with no charge. Examples of nonionic surfactant includealcohol ethoxylates (AE) including ethoxylated aliphatic alcohols. Ananionic surfactant has a polar head group with a negative charge.Examples of anionic surfactant are alkyl sulfates. A cationic surfactanthas a polar head group with a positive charge. Examples of cationicsurfactant are quaternary ammonium salts. A zwitterionic surfactant hasa polar head group with both a positive charge and a negative charge.Examples of zwitterionic surfactant include betaines and amphoacetates.The surfactant as interfacial surfactant in the fracturing fluid thatmay facilitate formation of the foam fracturing fluid or the emulsionfracturing fluid with the water as the continuous phase may be acationic compound, an anionic compound, a nonionic compound, or azwitterionic compound. For instance, the surfactant may be betaines,sulfated or sulfonated alkoxylates, alkyl quaternary amines, alkoxylatedlinear alcohols, alkyl sulfonates, alkyl aryl sulfonates, or C10-C20alkyldiphenyl ether sulfonates. The surfactant may be polyethyleneglycols, ethers of alkylated phenol, sodium dodecylsulfate, alpha olefinsulfonates (for example, sodium dodecane sulfonate), and trimethylhexadecyl ammonium bromide.

For embodiments of the VES-based fracturing fluid, a purpose of the VES(for example, cationic, anionic, nonionic, zwitterionic or amphoteric,or a combination of cationic and anionic surfactants) is to formmicelles to increase viscosity of the fluid to give the VES-based fluid.Cylindrical (truncated) or wormlike micelles give greater fluidviscosity than spherical micelles. Spherical micelles generally do notproduce viscosity. Truncated cylindrical micelles may make worm-like orrod-like micelles that entangle to give viscosity. VES-based systems mayinclude a surfactant (VES) capable of forming a wormlike micelle thatcan entangle and thus impart viscosity to the fluid. The fluid systemtypically includes salt to drive formation of the micelles, such asworm-like micelles that entangle. VES-based fluids may also contain abreaker to disrupt the micelles and reduce the viscosity while in theformation to enhance flowback.

Surfactant (VES) selection may be an aspect of formulating a VES-basedfracturing fluid. Under certain conditions, surfactant molecules arrangeinto colloidal structures called micelles as indicated earlier. Withthese structures, the hydrocarbon tails of the surfactants orient towardeach other while the polar head groups form an interface with thesurrounding aqueous media. In addition to surfactant selection,formulation of the present VES-based fracturing fluid may furtherinclude salt selection. The salts utilized may interactelectrostatically with the polar head groups and thereby reduce headgroup repulsion. This may cause a structural change to the micelle toideally form wormlike micelles that can entangle with one another andcause the viscosity of the VES-based fracturing fluid to increase. Awide range of salts are capable of interacting in this manner. Thesesalts can include monovalent or divalent salts.

Embodiments of the present VES-based fluid for hydraulic fracturinginclude water and surfactant (VES) to form the VES-based fluid. Themajority (>90 volume %) of the fluid is water. The amount of VES usedfor the fluid can range 4-8 volume % depending on the temperature andviscosity requirement. The VES concentration may fall below this range(and even approach zero) in the portion of the sequence or cycle of theintermittent adjustments when low viscosity in required. Again, the salt(e.g., from the brine) may promote micelle formation for increasedviscosity of the VES fluid. The salt may be a monovalent salt ordivalent salt, or other salt. The salt concentration in the fracturingfluid may approach zero in the portion of the sequence or cycle of theintermittent adjustments when low viscosity in required. Other fluidadditives in the VES-based fluid may include a breaker, stabilizer,microparticles, nanoparticles, crosslinker, corrosion inhibitor, scaleinhibitor, biocide, or pH buffer, or any combinations of these. In somecases, crude oil produced from formation may act as a viscosity breakerfor the VES fluid.

The VES-based hydraulic fracturing fluid may have a concentration of theVES, for example, in a range of 0.1 weight percent (wt %) to 10 wt %, ina range of 0.5 wt % to 7 wt %, or at least 1 wt %. The VES-basedhydraulic fracturing fluid may have a concentration of the VES, forexample, in a range of 2 vol % to 8 vol %. The VES may be, for example,a zwitterionic or amphoteric surfactant, a cationic surfactant, ananionic surfactant, a nonionic surfactant, or a combination of cationicand anionic surfactants. The zwitterionic surfactant may be a betaine,phosphobetaine, or sultaines. The cationic surfactant may include, forexample alkylammonium salts. Anionic surfactants as the VES for theVES-based hydraulic fracturing fluid may include alkyl sarcosinates orsulfonates. Nonionic surfactants as the VES for the VES-based hydraulicfracturing fluid may include amine oxides. The VES-based hydraulicfracturing fluid may include monovalent or divalent salts at aconcentration, for example, in ranges of 0.1 wt % to 20 wt %, 1 wt % to20 wt %, 0.1 wt % to 15 wt %, 1 wt % to 15 wt %, or less than 15 wt %.The salt concentration may be, for example, least 1 wt %, at least 3 wt%, at least 5 wt %, at least 7 wt %, at least 10 wt %, or at least 12 wt%. These salts may promote micelle formation, such as wormlike orcylindrical micelles, to increase viscosity of the fracturing fluid.These monovalent or divalent salts may include, for example, ammoniumchloride (NH₄Cl), sodium chloride (NaCl), potassium chloride (KCl),calcium chloride (CaCl₂)), strontium chloride (SrCl₂), sodium bromide(NaBr), and calcium bromide (CaBr₂).

VES-based fluids generally differ from conventional polymer-basedfracturing fluid systems. Polymer-based fracturing fluids typicallyincorporate a water-soluble polymer, clay control, surfactant, biocides,pH control, gel stabilizer, crosslinker, and breaker. A viscouspolymer-based fluid (for example, a gel at greater than 10 centipoise[cP]) is pumped into a geological formation and with the gel fluidtransporting proppant into a fracture network. Then, the gel is brokenby enzyme or oxidizer and the fluid flowed back from the formation tothe surface. This process may be operationally complex in relying onpolymer hydration and a variety of additives, such as biocides,crosslinkers, and breakers. By contrast, VES may be simpler to utilizein the field because typically there is no hydration step and becausefewer additives may be included. For example, in the case of breakers,VES-based fluids can break in the formation by changes in brineconcentration due to contact with produced fluids or alternatively bycontact with hydrocarbons which disrupt the surfactant micelles of theVES-based fluid. Further, an advantage of VES-based fluids overpolymer-based systems can be that VES-based fluids may typically besolids-free (except for any proppant). Therefore, in implementations,the VES-based fluids generally do not deposit residue in the geologicalformation or on the proppant pack. Thus, VES-based fluids may be moreefficient than polymer-based systems in hydraulic-fracture reservoirstimulation because the conductivity of the in-place proppant packaffects well productivity. In addition, VES-based fluids may heal afterexposure to shear. Additives may further improve the shear re-healingtime of the VES-based fluid gel. A benefit of healing may be thatviscosity is maintained for conveying proppant. The self-healing mayrestore the micelles and hence the viscosity. The VES fluid experiencesshear forces during pumping at the wellhead. The viscosity may berestored as the VES fluid goes into the wellbore and formation and thusperform hydraulic fracturing and convey proppant. Crosslinked polymerfluids, by contrast, can be irreversibly damaged during pumping becausethe shear forces cause some of the covalent bonds to break. The micellesof the VES fluid are not covalently held together and their formation isreversible. This may be an advantage of VES over crosslinked polymer forhydraulic fracturing. Embodiments employ VES gels to hydraulicallyfracture unconventional and conventional source-rock formations.

With respect to the proppant, the proppant may be coated proppant. Theunderlying proppant particle that receives the coating (e.g., resin,ceramic, etc.) may include particles of materials such as inorganicoxides, silicates, sand, graded sand, treated sand, ceramic, plastic,alumina, bauxite, silica, ceramic, thermoset resins, resin, epoxy,plastic, mineral, glass, silicon carbide, silicon nitride, zirconia,walnut hulls, composites of resin and other minerals or combinations ofthese. Proppant coatings protect the proppant particle from degradationcaused aqueous fluids at downhole temperatures. The proppant coatingincreases surface area of the particle and therefore crush stress isdistributed over a greater area of the coated proppant particle. Inturn, the distribution of force along a greater area should result indecrease in amount of crushed proppant particles, also known as thecrush percentage. The proppant coating also adheres to the proppant andmay prevent proppant that is crushed from releasing proppant fines.Proppant fines may migrate into the formation and restrict flowconductivity of the formation. Conventional uncoated proppant may breakunder downhole stress. Ceramic proppants not coated may break down inwet conditions, which cause them to lose their crush resistance.Temperatures downhole exacerbate this effect. Sand particles as proppantwithout coating may not provide sufficient crush resistance for use in agiven subsurface formation due to the polycrystalline nature of thegrains.

Resin coating as proppant coating may prevent or reduce crushing, finesmigration, proppant flowback, and breakdown of the proppant particle.The polymer or resin may include thermoset resin, polyester, ureaaldehyde, polyurethane, vinyl esters, or furfural alcohol, or anycombinations of these. Resin may be a substance of plant or syntheticorigin that is typically convertible into polymers. The resin may be amixture of organic compounds. In implementations, the viscosity of theresin may be greater than cP measured at a temperature of 120° C. Theresin may include phenolic resin, epoxy resin, furan resin, polyurethaneresin, polyurea resin, polyester, polyamide-imide resin, polyamide resinpolyurea/polyurethane resin, urea-formaldehyde resin, melamine resin,silicone resin, vinyl ester resin, or combinations of these. The resinmay be novolacs that are phenol-formaldehyde resins with a formaldehydeto phenol molar ratio of less than 1 and where the phenol units aremainly linked by methylene or ether groups, or both. Novolacs are stablemeaning that novolacs generally do not react and do retain their polymerproperties at temperatures of less than 300° F., 400° F., 450° F., 500°F., 550° F., or 600° F. The novolac polymer may have a glass transitiontemperature, for example, greater than 250° F., 300° F., 350° F., 390°F., 400° F., 450° F., or 500° F. Resoles are phenol-formaldehyde resinswith a formaldehyde to phenol molar ratio of more than 1 and where thephenol units are mainly linked by methylene or ether groups, or both.The resoles formulation can harden without the addition of acrosslinking agent due to abundance of methylene to bridge the phenolgroups. Both the novolac polymer and resoles may each have a molecularweight, for example, in ranges of 1,000 to 100,000 grams per mole(g/mol), 15,000 to 75,000 g/mol, or 10,000 to 50,000 g/mol.

The dispersion of strengthening agents (e.g., nanoreinforcing agents) inthe resin coating (or in ceramic coating) increases mechanical strengthof the coating materials. The dispersion of strengthening agent mayfurther provide resistance to chemicals present in hydraulic fracturingfluid. The resin coating may be resin nanocomposite coating including ananoreinforcing agent, a surface modifier, and resin, and which may beuniformly distributed throughout the resin nanocomposite coating.

The surface modifier imparts gas wetting characteristics to the resinnanocomposite coating (and to ceramic coating as well). This reduces theinterfacial tension and may prevent condensate or water blockage in thewellbore, increasing gas relative permeability and thereby reducingcondensate banking. The surface modifier may also impart hydrophobic oroleophobic characteristics to the proppant, such that water will not wetthe surface, which decreases degradation of the proppants caused bycontact with water. These wettability characteristics may increase theload recovery of hydraulic fracturing fluid or water after fracturingoperation as the hydrocarbons may generally experience less frictionfrom contact with the proppant. This may increase the rate ofhydrocarbon production and the overall amount of hydrocarbon produced.

The nanoreinforcing agent as incorporated in the resin coating orceramic coating may include or be ceramic, metallic, organic, inorganic,or mineral-based. Ceramic materials include, for example, alumina,zirconia, stabilized zirconia, mullite, zirconia toughened alumina,spinel, aluminosilicates (such as mullite or cordierite), siliconcarbide, silicon nitride, titanium carbide, titanium nitride, aluminumoxide, silicon oxide, zirconium oxide, stabilized zirconium oxide,aluminum carbide, aluminum nitride, zirconium carbide, zirconiumnitride, aluminum oxynitride, silicon aluminum oxynitride, silicondioxide, aluminum titanate, tungsten carbide, tungsten nitride,steatite, or any combination of these. Metallic materials include, forexample, iron, nickel, chromium, silicon, aluminum, copper, cobalt,beryllium, tungsten, molybdenum, titanium, magnesium, silver, as well asalloys of metals, and the like, or any combination of these. Metallicmaterials may also include the family of intermetallic materials, suchas iron aluminides, nickel alum inides, and titanium alum inides.Organic materials include, for example, carbon-based structures such ascarbon nanotubes, single walled carbon nanotubes (SWNT), double wallednanotubes (DWNT), multi-walled carbon nanotubes (MWNT), armchairnanotubes, zig-zag nanotubes, helical nanotubes, bundles of single wallnanotubes, bundles of multi-wall nanotubes, nanofibers, nanorods,nanowires, nanospheres, microspheres, whiskers of oxide, fullerenes,graphene, carbon fibers, graphite fibers, nomex fibers, or combinationsof these. Inorganic materials include, for example, vanadium pentoxidenanotubes, boron-nitride nanotube, tungsten, disulfidezinc oxide,diamond, clay, boron, boron nitride, silver, titanium dioxide, carbon,molybdenum disulfide, γ-aluminium oxide, titanium, palladium, tungstendisulfide, silicon dioxide, graphite, zirconium(IV) oxide-yttriastabilized, carbon, gd-doped-cerium(IV) oxide, nickel cobalt oxide,nickel(II) oxide, rhodium, sm-doped-cerium(IV) oxide, barium strontiumtitanate and silver. Mineral-based particulates include, for example,materials as kyanite, mica, quartz, sapphire, corundum, aluminosilicateminerals, and combinations of these. In certain implementations, thenano-reinforcing agent may be at least one of nano-silica, nano-alumina,nano-zinc oxide, carbon nanotubes, nano-calcium carbonate, mica,vanadium pentoxide, boron nitride nanotubes, or nano-zirconium oxide.

Reinforcing the ceramic matrix by mixing in two nanoreinforcing agentsmay increase the proppant crush resistance performance. The twonanoreinforcing agents may include: (1) the nanoreinforcing agent in theform of tubes, fibers, rope, fibrils, or combinations of these,dispersed in the ceramic coating and bonded to (2) the nanoreinforcingagent in the form of platelets, 2D surface, ribbons, or combinations ofthese. In some embodiments, the two nanoreinforcing agents may includecarbon nanotubes (which have an aspect ratio of greater than 100) andgraphene (which provides a 2D planar surface) to give mechanicalbridging throughout the proppant coating. This synergistic effectfurther improves electrical conductivity Reinforcing the resin (polymer)matrix (or reinforcing a ceramic coating matrix) by mixing in twonanoreinforcing agents may increase the proppant crush resistanceperformance. The two nanoreinforcing agents may include: (1) thenanoreinforcing agent in the form of tubes, fibers, rope, fibrils, orcombinations of these, dispersed in the ceramic coating and bonded to(2) the nanoreinforcing agent in the form of platelets, 2-dimensional(2D) surface, ribbons, or combinations of these. In some embodiments,the two nanoreinforcing agents may include carbon nanotubes (which havean aspect ratio of greater than 100) and graphene (which provides a 2Dplanar surface) to give mechanical bridging throughout the proppantcoating. The synergistic effect of combining carbon nanotubes withgraphene may further increase electrical conductivity as compared to aproppant coating including carbon nanotubes without graphene. Electricalconductivity can be utilized for mapping the fracture and alsodetermining the stimulated reservoir volume.

In some embodiments, the nanoreinforcing agent may include graphene andcarbon nanotubes, which can be a synergistic combination. The graphenemay increase strength of the proppant coating, increase conductivityassociated with the proppants, etc. The graphene can be, for example, inthe form of sheets, platelets, fibers, chemically-modified graphene,doped graphene, graphene nanotubes, functionalized graphene, grosslywarped nanographene, or combinations of these. In some implementations,the graphene includes graphene oxide, graphite, etc. Graphene orderivatives of these can be combined with one or more other types ofcarbon molecules such as diamonds, graphite nanotubes, fullerenes, orcombinations of these. The carbon nanotubes include at least one ofsingle-walled nanotubes, double-walled nanotubes, multi-walled carbonnanotubes, or narrow-walled nanotubes. The carbon nanotubes include adiameter of from 1 nm to 200 nm, from 20 nm to 100 nm, from 10 nm to 80nm, from 4 nm to 20 nm, from 2 nm to 12 nm, or less than 100 nm or lessthan nm. The carbon nanotubes include a length of from 20 μm to 500 μmor 50 μm to 200 μm, or less than 200 μm or less than 100 μm. The carbonnanotubes include an aspect ratio of from 100 to 100,000, from 100 to50,000, from 500 to 30,000, or less than 30,000. The term “aspect ratio”refers to a ratio of width to length. The coexistence of nanotubes andgraphene fillers shows a distinct synergistic effect in improving thetensile properties. The ability of nanotubes and graphene tosynergistically reinforce the polymer matrix is ascribed to theinterfacial interaction between filler and matrix and thenanotube-graphene interconnections. Specifically, the molecularcouplings between the nanotubes and graphene may transfer load when theproppant coating is under stress. Furthermore, the MWCNTs-GNPs networkstructures may dissipate mechanical energy throughout the proppantcoating. There are synergistic qualities of carbon nanotubes andgraphene.

Surface modifiers may be applied to the resin-coated proppant (or toceramic-coated proppant) to give wetting properties, enhance differentcomponent compatibility, or improve the appearance of a coating surface.The surface modifier may be at least one of an alkyl fluorosilanesolution, a fluorinated surfactant, a fluorinated polymer, and afluorinated polymeric surfactant. The alkyl fluorosilane solution, whichfunctions as a surface modifier, may includetriethoxy(tridecafluorooctyl) silane. The alkyl fluorosilane solutionmay include triethoxy(tridecafluorooctyl)silane, for example, in rangesof 1 volume percent (vol %) to 10 vol %, 1 vol % to 8 vol %, 1 vol. % to6 vol %, or 1 vol. % to 4 vol %, or at least 2 vol %. The surfacemodifier may include a solvent or alcohol (for example, propanol), forinstance, in a range of 90 vol % to 99 vol %. The surface modifier mayhave the following properties: a pH of less than 7, 6, 5, 4, 3, or 2; aboiling point in a range of 70° C. to 90° C. or 75° C. to 85° C., or atleast 75° C. (for example, about 82° C.); a viscosity in a range of 1millipascal seconds (m·Pas) to 10 m·Pas, 1 m·Pas to 5 m·Pas, 1 m·Pas to4 m·Pas, 2 m·Pas to 5 m·Pas, or 2 m·Pas to 4 m·Pas (for example, about 2m·Pas); and a density in a range of 0.5 gram per cubic centimeter (g/cm3) to 1.5 g/cm 3 or 0.7 g/cm 3 to 1 g/cm 3 (for example, about 0.8 g/cm3). In some instances of pillar fracturing, the permeability ofparticles may not play a significant role in production compared to theregions between the pillars. Yet, the coating may have a dual role ofhydrophobizing the particles, which may bring the particles closer foragglomeration and formation of pillar in the fluid. Once theresin-coated proppant is aggregated in pillar, the resin on particlesmay promote formation of a stable pillar by providing for bindingtogether of the proppant under formation heat and fracturing pressure.

As mentioned, the proppant may be resin-coated sand (RCS) orresin-coated proppant (RCP). The resin coating may havenanoreinforcement, as discussed. In other words, the resin coating(polymeric coating) may have nanoscale filler material, such asnanoparticles, nanotubes, nanofibers, nanoplatelets, etc. Thenanomaterials may be dispersed is solution in organic or inorganicsolvents as formed with the resin in resin coating and applied to thesand or proppant to enhance performance. The well-dispersed nanoscalestrong fillers (e.g., fibers, tubes, platelets, etc.) with high aspectratio and surface area may act to bridge the resin matrix against crackand fracture providing additional mechanical strength. An improvement inelectrical and thermal conductivity, as well as resistance to chemicaldegradation at elevated temperature, may be realized. In addition,certain embodiments provide for a synergistic effect of nanotubes andgraphene as nanofillers in the resin coating (or in ceramic coating) ofthe proppant. The reinforcing the resin matrix by mixing in amulti-walled carbon nanotubes (MWNT) dispersion together with graphenefurther increases proppant crush-resistance performance. The synergisticeffect of MWNT (e.g., in basic form of nano-sized ropes) and graphene(e.g. in the form of a two-dimensional [2D] planar surface), addsfurther enhancement of mechanical bridging across coating matrix andelectrical conductivity. The duel improvements may arise from thenanofiller in the form of tubes, fibers, rope or fibrils dispersed inpolymer matrix that strengthen the polymers the nanofiller in the formof platelets, 2D surface, ribbons, are further bonded. Proppant resincoatings that contain nanotubes and nanotubes may be toughened withgraphene. Features of applicable nanoreinforcement aspects of resincoating, the synergistic effect of nanotubes and graphene on theproppant resin coating, the thermal stability and chemical stability ofthe resin coating matrix, and effect of nanoreinforcement on long-termconductivity (per American Petroleum Institute [API] long-termconductivity test) including with respect to effect of surface areawettability are presented in US Published Patent Application No.2019/0345377 A1, which is incorporated by reference herein in itsentirety for all purposes. Lastly, the foregoing discussion with respectto nanoreinforcement may be applicable to ceramic coating ofceramic-coated proppant,

The proppant may include nano-functionalized coated proppant. Duringhydraulic fracturing operations, the surface of the proppant particlesmay interfere with fluid recovery or fluid flow therein due to frictionor drag forces, porosity, or hydrophilic property of surface.Additionally deterioration of proppant particulates by diagenesis mayreduce production. In response, the nano-functionalized coated proppantmay reduce the interfacial tension in the proppant pack in the pillarsand prevent or reduce condensate or water blockage in the near wellborearea. The nano-functionalized proppant may have wettabilitycharacteristics that are gas wetting and thus increase gas relativepermeability, which aid in reducing condensate banking. Thenano-functionalized coated proppant may impart hydrophobic and/oroleo-phobic (omniphobic) character to the proppant such that water willgenerally not wet the surface and thus corrosion of the proppant bywater may decrease. The wettability achieved by these proppant mayincrease load recovery of fracturing fluid or water after the fracturingoperation, thereby increasing fracture conductivity and production. Suchmay also facilitate increase in rate of production of oil and gas fromthe well at lower draw down pressures. Further, the non-Darcy andmultiphase flow effects are better addressed and therefore the retainedproppant-pack permeability may be enhanced. Furthermore, preparation ofnano-functionalized proppant with low surface energy and desired texturemay be implemented without modifying the commercially availablecoatings. The method functionalizes nanoparticles that can be added tothe resin during coating or dusted on the proppant coating duringmanufacturing to form the functionalized surface. The nanoparticles willhave functional group to form the covalent bonding with the resin. Also,relatively small quantity of functionalized nanoparticles may beincluded the coating. The resin can be reinforced with other material,such as carbon nanotubes, silica, alumina, mica etc., to providetoughness to the coating.

Some embodiments of the present proppant have a proppant coating that isunfunctionalized organic resin with functionalized nanoparticles and astrengthening agent. Thus, the proppant may have nanoparticle coatingthat is resin coating with nanoparticles. This proppant coating preventsor reduces crushing, fines migration, proppant flowback and breakdown ofthe proppant particle. The functionalized nanoparticles in the proppantcoating impart hydrophobicity, oleophobicity, or omniphobicity to theproppants without the need for an expensive hydrophobic functionalizedresin. The functionalized nanoparticles may adhere to theunfunctionalized organic resin. The functionalized nanoparticles provideresistance to the chemicals present in hydraulic fracturing fluid. Thedispersion of strengthening agent(s) enhances the mechanical strength ofthe coating. Unfunctionalized organic resin is a substance of plant orsynthetic origin that is typically convertible into polymers, and may bea mixture of organic compounds such as terpenes, an organic compoundproduced by plants. The viscosity of resin may be greater than 20 cPmeasured at a temperature of 120° C. In one embodiment, theunfunctionalized organic resin may have no additional additives. Theunfunctionalized organic resin may be at least one of phenolic resin,epoxy resin, furan resin, polyurethane resin, polyurea resin, polyester,polyamide-imide resin, polyamide resin polyurea/polyurethane resin,urea-formaldehyde resin, melamine resin, silicone resin or vinyl esterresin, or mixtures thereof. In implements, the unfunctionalized organicresin includes phenol-formaldehyde. The phenolformaldehyde resin maycomprise novolac or resole. Novolacs are phenol-formaldehyde resins witha formaldehyde to phenol molar ratio of less than 1, where the phenolunits are mainly linked by methylene or ether groups, or both. Thestrengthening agent may be nanoparticles, nanofibers, micro-fibers,microparticles. The strengthening agent may include carbon nanotubes,silica, alumina, glass, mica, graphite, talc, nanoclay, graphene, carbonnanofibers, boron nitride nanotubes, vanadium pentoxide, zinc oxide,calcium carbonate, zirconium oxide, titanium oxide, silicon nitride,silicon carbide, and aramid fibers. The carbon nanotubes may besingle-walled nanotubes, double-walled nanotubes, multi-walled carbonnanotubes, narrowwalled nanotubes, or bundle of nanotubes. Preparationof the resin coating may including to functionalize nanoparticles togive the functionalize nanoparticles. The method may involve reactingnanoparticles with at least one of an alkoxysilane solution or ahalosilane solution to form functionalized nanoparticles, in whichfunctionalized nanoparticles include nanoparticles having fluorosilane,perfluorosilane or alkylsilane moieties attached to the nanoparticles.The underlying proppant particles may be coated with theunfunctionalized organic resin, strengthening agent, and thefunctionalized nanoparticles to give the resin coated proppant.

FIG. 4A and FIG. 4B are a reaction forming an example functionalizednanoparticle to be included with the unfunctionalized organic resin andstrengthening agent in the resin coating. The functionalizednanoparticles may be formed by reaction with at least one ofalkoxysilanes and halosilanes comprising hydrophobic moiety, oleophobicmoiety, or omniphobic moiety. The alkoxysilanes bond to the surfacesilanol groups of silica nanoparticles, forming a 1-3 Si—O—Si link in acondensation reaction with elimination of an alcohol. The halosilaneshydrolyze, substituting the halogen group for an alcohol group, whichthen undergoes a condensation reaction with surface silanol groups,functionalizing the nanoparticles with low surface energy moiety. Thisreaction is illustrated in FIGS. 4A and 4B. Although the figures includetrichlorosilanes, other halogens may be used in place of the chlorine,such as bromine. Silylethers can also be, for example,perfluorooctyltrimetoxysilane or perfluorooctyltriethoxysilane.Similarly, to make particles hydrophobic, long chain hydrocarbon andsilicone derivatization can be done. Such may help in agglomeration ofproppant to form pillars in aqueous fracturing fluid.

FIG. 5 is an example of an epoxy terminal binding group on thefunctionalized nanoparticle. In some embodiments, the nanoparticles maybe further functionalized with a coupling agent. One end of the couplingagent will bind to the nanoparticles while the other end will bind tothe unfunctionalized organic resin, thereby bonding the functionalizednanoparticles to the unfunctionalized organic resin. The terminalbinding group may include at least one of an epoxy group, an aminegroup, methyacryloxy group, acrylamide group, aminophenyl group,carboxyl group, halogen group, hydroxyl group, isocyanate group,mercapto group, allyl group or a silane ester group that reacts with thenanoparticles and binds with the unfunctionalized organic resin orreacts with the unfunctionalized organic resin to form a bond. In someembodiments, the epoxy containing composition is an epoxysilane with aterminal epoxy group. In some embodiments, the epoxy-containingcomposition is an alkoxysilane. In some embodiments, theepoxy-containing composition is a silane coupling compound with aterminal reactive group. Examples of silane coupling compound withterminal reactive groups includes but not limited toγ-glycidoxypropyltriethoxysilane, γ-aminopropyltriethoxysilane,γ-(methacryloxy)propyl trimethoxysilane, 3-acrylamidopropyltrimethoxysilane, 4-aminobutryltriethoxysilane,p-aminophenyltrimethoxysilane, carboxyethylsilanetriol sodium,4-bromobutyltrimethoxysilane, 2-(chloromethyl)allyltrimethoxysilane,hydroxymethyltriethoxysilane, 3-isocyanotopropyltrimethoxysilane,3-mercaptopropyltrimethoxysilane and allyltrimethoxysilane. The terminalgroup on nanoparticles are added to react with various unfunctionalizedorganic resin systems such as phenolic resin, epoxy resin, furan resin,polyurethane resin, polyurea resin, polyester, polyamide-imide resin,polyamide resin polyurea/polyurethane resin, ureaformaldehyde resin,melamine resin, silicone resin and vinyl ester resin.

Ceramic-coated proppant can be used for pillar formation. The ceramiccoated proppant can be further coated with resin to form strongerpillars by agglomeration. Ceramic-coated proppant can be mixed withlighter proppants to form pillars by settling velocity difference.

The proppant utilized to form the pillars of proppant may includeceramic-coated proppant. The ceramic coating on the proppant may includea ceramic matrix composite (CMC). The ceramic-coated proppant may beceramic-coated sand. To form the ceramic-coated proppant for use in thepillar fracturing, particles (e.g., sand particles or other particles)are coated with ceramic and the ceramic coating sintered to strengthenthe underlying particle as a proppant. Examples of the ceramic includebauxite, kaolin, and alumina. In certain embodiments, ceramic fibers maybe incorporated into the ceramic coating to give ceramic matrixcomposite (CMC) coating that increases the crack resistance or fracturetoughness of the ceramic-coated proppant. In general, a ceramic materialis an inorganic non-metallic material and may include, for example,crystalline oxide, alumina, nitride, or carbide material. Some elements,such as carbon or silicon, may be considered ceramics. The underlyingproppant (underlying core particles) coated with the ceramic may beinorganic or organic. The inorganic particles include, for example,sand, ceramic, or metal. The organic particles include, for example,walnut hull, thermoplastic resin, polymer derived resin (PDR), orthermoset resin (for instance, epoxy or phenolic). Ceramic proppants canbe coated with ceramic coating to improve the performance and propertiesof the already existing ceramic proppants. For instance, a ceramicproppant may have inadequate strength or inadequate chemical resistanceto corrosion. The ceramic coatings of the present techniques mayincrease strength and chemical resistance of the underlying ceramicproppant. In some cases, a plastic proppant is coated with ceramic togive proppant of adequate strength with reduced density. Inorganicproppant, such as sand, alumina-based proppant, silicate-based proppant,or metal-oxide proppant may be coated with ceramic. Organic proppant,such as walnut hull or thermoset resin, may be coated with ceramic. Thesuccess of the hydraulic-fracturing stimulation may partially depend onthe strength of the proppant to withstand formation closure stresses. Asdiscussed, crushing of proppant under formation closure stressesgenerates fines which can cause plugging reducing conductivity and thusreducing flow of produced hydrocarbon. Proppant with increased strengthvia the ceramic coating is generally more resistant to crushing andassociated fines generation that reduce conductivity. Further, proppantmade stronger via the ceramic coating can typically better hold thefracture open and maintain the conductivity of the fracture forhydrocarbon to flow.

Sand and ceramic proppant may be coated with resins. Examples of resinsinclude furan resin, epoxy resin, polyurethane resin, phenolic resin,polyester resin, polyurea resin, and polyimide resin. The proppant iscoated with resin to enhance strength, chemical resistance, and proppantflowback control, and to prevent or reduce crushed generated fines frommigrating. However, resin coating may suffer drawbacks. While resincoating may increase the crush strength of the proppant by distributingthe stress over a larger area, the core-material crush strength mayremain unchanged for resin coatings without strengthening or reinforcingagents. Further, resin coating generally degrades over time in wellboreconditions. Also, resin may become plasticized when the resin absorbswater or oil in typical wellbore conditions. Wellbore temperature canfurther contribute to the proppant becoming plasticized. The plasticizedresin coating can creep into the pore space of proppant pack and therebyreduce conductivity. Such creep can be accelerated in presence offormation temperatures greater than typical. Furthermore, cross-linkedresin coatings can become brittle under heat and disintegrate, which cangenerate plastic fines that plug the proppant pack. Lastly, some resinsystems are affected by corrosive chemicals, such as acid or base. Forexample, phenolic resins may be degraded by fluids having a pH greaterthan 9 or 10.

Sand and ceramic proppant can be coated with preceramic polymers orpolymer-derived-ceramics (PDCs) resin. Polymer-derived-ceramics (PDCs)define a class of ceramic materials that are synthesized by thermaltreatment (usually pyrolysis) of ceramic precursors (so-calledpreceramic polymers) under an inert or reacting atmosphere. By utilizingpreceramic polymers, ceramic compositions such as amorphous siliconcarbide (SiC), silicon oxycarbide (SiOC), and silicon carbonitride(SiCN), can be obtained after heat treatment, for example, at 1000-1100°C. in an inert atmosphere (argon or nitrogen). As there is generally nosintering step, PDC parts can be formed in some implementations withoutpressure at lower temperatures relative to traditional ceramic powdershaping technologies. Preceramic polymers can be processed utilizingexisting technologies suitable for polymers in general. Due to the PDCdistinctive nanostructure of carbon-rich and free carbon domains, PDCsmay show exceptional stability against oxidation, crystallization, phaseseparation, and creep even up to 1500° C. PDCs have been successfullyemployed for the fabrication of ceramic fibers, ceramic matrixcomposites (CMCs), and microstructures that may be part of the proppantcoating.

Ceramic-coated proppant may increase the crush strength of the proppantmaterial while avoiding shortcomings of resin-coated proppant. Inorganicproppant or particles and organic proppant or particles may be coatedwith ceramic compositions to give ceramic-coated proppant. The inorganicproppant that receives the ceramic coating may be ceramic, or proppantor particles that are non-ceramic (for example, sand or metal). Theorganic proppant that receives the ceramic coating may be, for example,walnut hulls or resin proppant. In the case of sand, the ceramic coatingof sand may increase the crush strength of the proppant sand, therebyextending applications in hydraulic fracturing of proppant sand ascompared to usage of the base proppant sand without coating. Theproppant receiving the ceramic coating may be considered the coreproppant (or core particles) and be inorganic particles (for example,sand particles, ceramic particles, or metal particles), organicparticles, or non-ceramic particles (for example, sand or metalparticles), as discussed. The techniques may prepare strengthenedproppant by ceramic-coating the core proppant particles.

FIG. 6 is a method 600 of forming a ceramic-coated proppant 610. Theceramic-coated proppant 610 may be utilized in the present techniques offorming proppant pillars in hydraulic fracturing. The method 600includes receiving core particles 602, which may be ceramic proppant orparticles, or may be sand or other proppant or particles that are notceramic. The particles 602 may be the underlying core proppant of theceramic-coated proppant 610.

At block 604, the method includes coating the particles 602 with ceramicto give a ceramic coating on the particles 602. The ceramic coating maybe formed on the particles 602 by applying ground ceramic to theparticles 602. Coating the particles 602 with ceramic may involvecoating the particles 602 with ground ceramic including calcined clay,uncalcined clay, bauxite, silica, or alumina, or any combinationsthereof. The alumina content of the ground ceramic may be greater than40 wt %. The ground ceramic may include a reinforcing agent(s) so that aCMC will form. Applying the ground ceramic may include coating theparticles 602 with the ground ceramic via a drum coater, a mixinggranulator, or spray coating, or any combinations thereof. The ceramiccoating may be formed on the particles 602 by applying a slurry of theaforementioned ground ceramic to the particles 602. The coating of theparticles 602 with ceramic may involve coating the particles 602 with aslurry having the ground ceramic and water. In implementations, theslurry has a solids content in a range of 10 wt % to 50 wt %. Thecoating of the proppant via the slurry may include coating the proppantwith the slurry by drum coating, spray coating, fluidized-bed coating,or wet-dip coating, or any combinations thereof. The ceramic coating maybe formed on the particles 602 by applying ceramic to the particles 602by solution gelation. The ceramic coating may be formed on the particles602 by applying alumina-silica sol-incorporated alpha-alumina to theparticles 602. The ceramic coating may be formed on the particles 602 byapplying a CMC having fibers to the particles 602. The ceramic coatingmay include organic fibers, inorganic fibers, organic particles, orinorganic particles, or any combinations thereof.

At block 606, the method includes drying the ceramic coating on theparticles 602. The particles 602 having the ceramic coating may be driedat temperatures greater than ambient. In one implementation, the coatedparticles are dried at a temperature of at least 120° C. for at least 2hours. The method may include densifying the ceramic coating by thermaltreatment at a temperature, for example, in a range of 600° C. to 1400°C.

At block 608, the method includes sintering the ceramic coating on theparticles 602 to give the ceramic-coated proppant 610. The particles 602as coated may be sintered in a rotary kiln or via microwave sintering,or both. The ceramic coating may have a sintering aid such as FeO,Fe2O3, Fe3O4, MgO, ZnO, MnO, or Mn2O3, or any combinations thereof. Thecoated particles may be sintered at a temperature, for example, in therange of 600° C. to 1400° C., or at a temperature less than 1200° C.

A method of hydraulic fracturing including to form pillars of proppantincluding ceramic-coated proppant may include adding ceramic-coatedproppant to fracturing fluid. The ceramic-coated proppant may be coreproppant coated with a ceramic coating. The core proppant may be anon-ceramic particle (for example, sand, metal particle, or organicparticle) or a ceramic particle. The ceramic in the ceramic coating mayhave an alumina content greater than 40 weight percent. The ceramiccoating may include a binder, for example, at less than 1.5 weightpercent of the ceramic coating. The ceramic coating may have a bondingadditive to restrict delamination of the ceramic coating. The method ofhydraulic fracturing may include injecting a fracturing fluid through awellbore into a subterranean formation. The fracturing fluid may havethe added ceramic-coated proppant. The injecting of the fracturing fluidmay include pumping the fracturing fluid from the Earth surface into thewellbore. The fracturing fluid may flow through perforations (formedthrough wellbore casing) into the subterranean formation. The methodincludes hydraulically fracturing the subterranean formation with thefracture fluid to generate fractures in the geological formation. Thefracturing fluid generating the fractures in the subterranean formationmay include ceramic-coated proppant. The method includes positioning theceramic-coated proppant in the fractures to support the fractures withthe ceramic-coated proppant. The injected fracturing fluid having theceramic-coated proppant may distribute the ceramic-coated proppant intothe fractures. The method includes intermittently adjusting acharacteristic of the fracturing fluid to affect the distribution toform pillars (accumulations) of the ceramic-coated proppant in thefractures. The pillars of proppant may maintain open the fractures. Theceramic-coated proppant may be sintered or densified ceramic-coatedproppant to increase strength of the proppant for maintaining open thefractures. The ceramic coating of the proppant may include organicfibers, inorganic fibers, organic particles, inorganic particles, or aCMC, or any combinations thereof.

The particles (core proppant) that receives the ceramic-coating mayinclude proppant materials to be strengthened by coating with ceramic.The ceramic-coated particles (ceramic-coated proppant) formed may havegreater sphericity than the starting-material particles (core proppant).The ceramic-coated proppant may be sintered to provide enhancedstrength. The ceramic-coated proppant may have greater compressivestrength than the core proppant. Thus, the core proppant (for example,sand) as coated may be employed in environments having closure stressesin which typically the core proppant is not employed. Inimplementations, the compressive strength of the core proppant may beincreased with the ceramic coating by a range of 10% to 300%. The crushresistance stress level (or crush strength) per International StandardISO 13503-2 (First edition 2006-11-01) by the International Organizationfor Standardization can reach between 10,000 pounds per square inch(psi) to 40,000 psi. The particles or proppant as core proppant to bestrengthen with ceramic coating may include ceramic proppant, walnuthulls, cementitious particles, and sand (for example, brown sand,multicrystalline sand, or angular sand). The particle size of the coreproppant may range from 100 mesh (150 microns) to 12/20 mesh (850microns to 1700 microns). An example of brown sand is referred to asBrady sand mined from central Texas in the United States of America.

In some implementations, the proppant ceramic-coating coating of presenttechniques may be optionally coated or treated with agents to modify thewettability of the proppant. In certain embodiments, the ceramic-coatedproppant is treated with fluorosilane (SiH3F) to give the ceramic-coatedproppant a hydrophobic character. In particular implementations, thistreating with fluorosilane is performed while the ceramic-coatedproppant is cooling after sintering. The fluorosilane may be sprayedonto the ceramic-coated proppant when temperature of the proppant isapproximately in the range of 50° C. to 100° C., and the proppanttumbled to promote modifying of the surface of the ceramic-coatedproppant. Other surface modifications may make the surface hydrophobicor omniphobic.

FIG. 7 is a proppant 700 that may be utilized in the generation ofpillars of proppant. The proppant 700 has a core particle 702 and aceramic coating 704. Thus, the proppant 700 may be characterized as aceramic-coated particle or ceramic-coated proppant. The core particle702 may be inorganic (for example, sand, ceramic, or metal) or organic(for example, walnut hull). In some implementations, the core particle702 itself is a proppant. Thus, the proppant 700 may be a ceramic-coatedproppant with the underlying core particle 702 as a proppant. The coreparticle 702 can generally be any proppant or proppant-like material.The core particle 702 can be ceramic proppant. The core particle 702 canbe non-ceramic proppant, such as sand, metal, or organic proppant. Theceramic coating 704 can be formed on the underlying proppant or particleby coating particles with ground ceramic, coating particles with groundceramic slurry, coating particles with ceramic via solution-gelation,coating particles with ceramic via alumina-silica sol-incorporatedalpha-alumina powder, and coating particles with ceramic coating havingceramic fibers embedded in CMC. The ceramic coating 704 can include CMC.CMCs include a reinforcing agent (for example, fibers) embedded in aceramic matrix. The matrix and reinforcing agent can typically consistof any ceramic material, whereby carbon and carbon fibers can also beconsidered a ceramic material. The matrix and reinforcing agent can bethe same ceramic material type. Examples the reinforcing agent includeceramic fibers that are carbon (C), silicon carbide (SiC), alumina(Al2O3), and mullite (Al2O3—SiO₂). In some implementations, the ceramicmatrix materials can also be C, SiC, alumina, or mullite. Examples ofCMCs (fiber/type of matrix) are Al2O3/Al2O3, C/C, C/SiC, and SiC/SiC.Further, the CMC may include a non-ceramic reinforcing agent(s) inaddition to the ceramic reinforcing agent(s). In implementations, thereinforcing agent(s) is less than 5 wt % of ceramic coating 704, lessthan 2 wt % of the ceramic coating 704, or less than 1 wt % of theceramic coating 704.

A surface modifier may be applied to the proppant 700. For example, theceramic coating 704 may be coated or treated with surface modifier. Asurface modifier may be agents (for example, SiH3F) to modify thewettability of the proppant 700. The surface modifiers may be applied tothe ceramic-coated proppant 700 (or to the ceramic-coated proppant 800of FIG. 8 ) to give wetting properties, enhance different componentcompatibility, or improve the appearance of a coating surface. Thesurface modifier may be at least one of an alkyl fluorosilane solution,a fluorinated surfactant, a fluorinated polymer, and a fluorinatedpolymeric surfactant. The alkyl fluorosilane, which functions as asurface modifier, may include triethoxy(tridecafluorooctyl)silane. Thesurface modifier imparts gas wetting characteristics to the ceramiccoating 704. Thus, application of the surface modifier may reduceinterfacial tension and therefore reduce condensate or water blockage inthe wellbore, which may increase gas relative permeability and reducecondensate banking. These wettability characteristics enhance the loadrecovery of hydraulic fracturing fluid or water after fracturingoperation as the hydrocarbons may experience less friction from contactwith the proppant. Consequently, the rate of hydrocarbon production andthe overall amount of hydrocarbon production may be increased. Thesurface modifier may impart hydrophobic or oleophobic characteristics tothe proppant, such that water will generally not wet the surface andthus the degradation of the proppants due to contact with water may bedecreased. Moreover, hydrophobic interaction of hydrophobic proppant maycontribute to agglomeration of the proppant in the pillars.

As similarly discussed with respect to resin coating, thenanoreinforcing agent enhances the mechanical strength of the ceramiccoating 704 and provides resistance to chemicals utilized in hydraulicfracturing fluid. The nanoreinforcing agent may include ceramicmaterials, metallic materials, organic materials, inorganic materials,or mineral-based materials, as listed above. In one implementation, thecoating 704 includes a reinforcing agent that is a coated carbonnanotube, such as zinc sulfide (ZnS) coated carbon nanotubes. ZnS coatedcarbon nanotubes provide additional thermal stability and mechanicalstrength. Weight loss as a function of temperature for ZnS-coatedmulti-walled carbon nanotubes (MWCNT) is less than for non-coated MWCNT.The ZnS coated multi-walled carbon nanotubes retain greater weight inthermo-gravimetric analysis (TGA) compared to multi-walled carbonnanotubes without a ZnS coating. In another implementation, the ceramiccoating 704 includes silica (SiO2) coated single-walled carbon nanotubes(SWNT). SiO2 coated carbon nanotubes may better fuse with neighboringproppants in a pillar for agglomeration of proppant in the pillar,generate a stronger proppant pack, and mitigate proppant flowback.

For the CMC of the ceramic coating 704 as a nanocomposite, thereinforcing agents may include nanoreinforcing agents (or nanofillers).More than one type of nanoreinforcing agent may be employed in the CMC.Certain implementations provide for a synergistic effect between twonanoreinforcing agents in the CMC or between a nanoreinforcing agent andthe ceramic matrix in the CMC. As discussed with respect to resincoating, the nanoreinforcing agent may include graphene and carbonnanotubes in certain implementations. The graphene may increase thestrength of the ceramic coating on the proppant, increase theconductivity of the ceramic-coated proppants, or both. As indicated,graphene can be provided in multiple desirable forms or combination offorms, for example, sheets, platelets, fibers, chemically-modifiedgraphene, doped graphene, graphene nanotubes, functionalized graphene,grossly warped nanographene, or combinations of these. In someembodiments, the graphene includes graphene oxide or graphite, or acombination thereof. The carbon nanotubes may be single-wallednanotubes, double-walled nanotubes, multi-walled carbon nanotubes, ornarrow-walled nanotubes, or any combinations thereof. The carbonnanotubes include values for diameter and aspect ratio, as listed above.Reinforcing the ceramic matrix by mixing in two nanoreinforcing agentsmay increase the proppant crush resistance performance. As discussedsimilarly with respect to resin coating, the two nanoreinforcing agentsmay include: (1) the nanoreinforcing agent in the form of tubes, fibers,rope, fibrils, or combinations of these, dispersed in the ceramiccoating and bonded to (2) the nanoreinforcing agent in the form ofplatelets, 2D surface, ribbons, or combinations of these. In someembodiments, the two nanoreinforcing agents applied to give synergisticresults in combination may include carbon nanotubes (which have anaspect ratio of greater than 100) and graphene (which provides a 2Dplanar surface) to give mechanical bridging throughout the proppantcoating.

In certain implementations, the ceramic-coated proppant may be furthercoated with thermoset resin such as phenolic, epoxy, furan, urethane,polyimide, polyester, polyurea and the like. See, for example, FIG. 8 .These thermoset-resin coatings may increase the strength ofceramic-coated proppant. In some cases, this thermoset resin on theceramic coating may increase the binding of ceramic-coated particles ina proppant pack or pillar for flowback proppant control. The appliedresins as functionalize can be made hydrophobic, hydrophilic,non-wetting, omniphobic, or intermediate wet depending on theapplication. Again, the ceramic-coated particle can further be coatedwith a resin (for example, a thermoset resin).

FIG. 8 is a ceramic-coated proppant 800 that may be utilized as proppantin the formation of pillars of proppant in fractures in hydraulicfracturing. The ceramic-coated proppant 800 is the ceramic-coatedproppant 700 (FIG. 7 ) having a polymer coating 802 (an outer polymerlayer). Thus, the ceramic-coated proppant 800 may be characterized asdouble coated. The ceramic-coated proppant 800 includes the coreparticle 702 (for example, core proppant) having the ceramic coating 704and the polymer coating 802. The ceramic-coated proppant 800 includesthe polymer coating 802 at a weight percent in a range of 0.5% to 15%,0.5% to 10%, 1.0% to 8%, 1.5% to 6%, 1.0% to 5%, or 0.5% to 4.5%, or atleast 2% or at least 4%. In hydraulic fracturing of a geologicalformation with hydraulic fracturing fluid having the ceramic-coatedproppant 800, the polymer coating 802 may facilitate pillar fracturingand flow back. When the polymer coating 802 (outer polymeric layer) isdegraded, the ceramic coating 704 provides for longer service life ofthe proppant 800 than without the ceramic coating 704. The polymerapplied as the polymer coating 802 may include resin (includingthermoset resin), polyester, urea aldehyde, polyurethane, vinyl esters,or furfural alcohol, or any combinations of these. In implementations,the resin may be a mixture of organic compounds and is typicallyconvertible into polymers. The viscosity of resin when applied may be,for example, greater than 20 cP measured at a temperature of 120° C. Theresin may include phenolic resin, epoxy resin, furan resin, polyurethaneresin, polyurea resin, polyester, polyamide-imide resin, polyamide resinpolyurea/polyurethane resin, urea-formaldehyde resin, melamine resin,silicone resin, vinyl ester resin, or combinations of these. The resinmay be novolacs or resoles.

An embodiment is a method of hydraulic fracturing, including injecting afracturing fluid through a wellbore into a geological formation. Thefracturing fluid includes a ceramic-coated proppant that is a coreproppant coated with a ceramic coating, wherein the core proppant doesnot include ceramic. The core proppant may include walnut hulls,cementitious particles, or sand, or any combinations thereof. Theceramic-coated proppant may be further coated with a resin. The methodincludes hydraulically fracturing the geological formation with thefracturing fluid to generate fractures in the geological formation, andconveying the ceramic-coated proppant via the fracturing fluid into thefractures. The method includes intermittently adjusting a characteristic(e.g., rheology, rheological property, viscosity, viscoelasticity,proppant suspension, proppant settling velocity, surfactantconcentration, salt concentration, FQ, etc.) of the fracturing fluidconveying the proppant to form pillars of the ceramic-coated proppant inthe fractures.

Another embodiment is a system for hydraulic fracturing. The systemincludes a source of fracturing fluid. The system includes a pumpoperationally coupled to the source to provide the fracturing fluidthrough a wellbore into a subterranean formation to hydraulicallyfracture the subterranean formation to generate fractures in thesubterranean formation, wherein the fracturing fluid to convey proppantinto the fractures. The system includes a control system tointermittently adjust a characteristic of the fracturing fluid conveyingthe proppant to form pillars of proppant in the fractures. Theintermittent adjustments may be at a frequency having an interval in arange of 2 minutes to 100 minutes. The characteristic comprisesviscosity or proppant suspension, or both. The characteristic may beconcentration of a surfactant in the fracturing fluid. Thecharacteristic may be concentration of microparticles or concentrationof nanoparticles, or both, in the fracturing fluid. The fracturing fluidmay be foam fracturing fluid, wherein the characteristic isconcentration of a foaming surfactant in the foam fracturing fluid. Thecharacteristic may be FQ of the foam fracturing fluid, and wherein tointermittently adjust the FQ includes to adjust an amount of gas (e.g.,nitrogen) or supercritical CO2, or both, in the fracturing fluid to formthe pillars of proppant in the fractures. The fracturing fluid may beVES-based fracturing fluid, wherein the characteristic is concentrationof VES in the VES-based fracturing fluid. The characteristic may beconcentration of salt in the VES-based fracturing fluid or in the brineadded to the VES-based fracturing fluid. The characteristic may be atype of salt in the brine or in the VES-based fracturing fluid. Thefracturing fluid may be oil-based fracturing fluid, and wherein thecharacteristic is concentration of crosslinker metal ions in theoil-based fracturing fluid. The fracturing fluid may be emulsionfracturing fluid, wherein the characteristic is at least one ofconcentration of an emulsifying surfactant in the emulsion fracturingfluid or ratio of water to oil in the emulsion fracturing fluid. Theproppant may be proppant having advanced coatings. In particular, asdiscussed, the proppant may be resin-coated proppant or ceramic-coatedproppant (e.g., having CMC). The proppant may be double-coated proppantin having a ceramic coating and an outer polymer layer as a resincoating on the ceramic coating.

Yet another embodiment is a method of hydraulic fracturing, including:(1) providing a fracturing fluid through a wellbore into a subterraneanformation; (2) hydraulically fracturing the subterranean formation withthe fracturing fluid, thereby generating fractures in the subterraneanformation; (3) conveying proppant in the fracturing fluid through thewellbore into the fractures; and (4) intermittently adjusting acharacteristic of the fracturing fluid conveying the proppant to formpillars of proppant in the fractures. To form the pillars may involve toagglomerate the proppant. The characteristic intermittently adjusted maybe rheology or a rheological property. The characteristic may beviscosity or proppant suspension, or both. In implementations,intermittently adjusting the characteristic does not involve changingtype of fracturing fluid or pulsing different types of fracturing fluid.In some implementations, intermittently adjusting the characteristicincludes adjusting the characteristic at a frequency including aninterval in a range of 2 minutes to 2 hours, or in a range of 2 minutesto 100 minutes. The characteristic may be concentration of surfactant inthe fracturing fluid, concentration of salt in brine added to thefracturing fluid, or concentration of salt in the fracturing fluid, orany combinations thereof. The characteristic may be concentration ofmicroparticles or concentration of nanoparticles, or both, in thefracturing fluid. In certain implementations, the fracturing fluid hasfoam (and thus the fracturing fluid may be foam fracturing fluid),wherein the characteristic intermittently adjusted is associated withthe foam, may be at least one of foam stability or concentration offoaming surfactant in the fracturing fluid, and/or may be FQ (e.g., inthe range of 52% to 80% by volume). Intermittently adjusting theconcentration of the foaming surfactant (if such adjustmentsimplemented) may involve repeatedly cycling through a firstconcentration of the foaming surfactant in the foam fracturing fluid anda second concentration of the foaming surfactant in the foam fracturingfluid different than the first concentration. Likewise, intermittentlyadjusting the concentration of the foaming surfactant may involverepeatedly cycling through a first concentration of the foamingsurfactant in the foam fracturing fluid, a second concentration of thefoaming surfactant in the foam fracturing fluid different than the firstconcentration, and a third concentration of the foaming surfactant inthe foam fracturing fluid different than the first concentration and thesecond concentration. The fracturing fluid may be VES-based fracturingfluid. The characteristic intermittently adjusted may be concentrationof VES in the VES-based fracturing fluid. Intermittently adjusting theconcentration of the VES in the VES-based fracturing fluid includesrepeatedly cycling through a first concentration of the VES in theVES-based fracturing fluid and a second concentration of the VES in theVES-based fracturing fluid different than the first concentration.Similarly, intermittently adjusting the concentration of the VES in theVES-based fracturing fluid includes repeatedly cycling through a firstconcentration of the VES in the VES-based fracturing fluid, a secondconcentration of the VES in the VES-based fracturing fluid differentthan the first concentration, and a third concentration of the VES inthe VES-based fracturing fluid different than the first concentrationand the second concentration. The characteristic intermittently adjustedmay be concentration or type of salt in brine incorporated intoVES-based fracturing fluid or concentration or type of salt in theVES-based fracturing fluid, or any combinations thereof. Intermittentlyadjusting the type of the salt (if such adjustments implemented) mayinvolve repeatedly cycling through a first salt type that is divalentsalt and a second salt type that is monovalent salt. The characteristicintermittently adjusted may be concentration of microparticles orconcentration of nanoparticles, or both, in the VES-based fracturingfluid. The fracturing fluid may be oil-based fracturing fluid, whereinthe characteristic intermittently adjusted may be concentration ofcrosslinker metal ions in the oil-based fracturing fluid. The fracturingfluid may be emulsion fracturing fluid, and wherein the characteristicintermittently adjusted may include concentration of an emulsifyingsurfactant in the emulsion fracturing fluid or a ratio of water to oilin the emulsion fracturing fluid, or a combination thereof. Thefracturing fluid may be emulsion fracturing fluid, wherein thecharacteristic intermittently adjusted may be concentration of salt inbrine incorporated into the emulsion fracturing fluid or concentrationof salt in the emulsion fracturing fluid, or a combination thereof. Thefracturing fluid may be emulsion fracturing fluid, wherein thecharacteristic intermittently adjusted may be a concentration ofmicroparticles or nanoparticles, or both, in the emulsion fracturingfluid.

Intermittently adjusting the characteristic to form the pillars in thefractures may utilize less proppant than conveying the proppant to thefractures without adjusting the characteristic and with depositing theproppant in the fractures without forming the pillars in the fractures.In other words, implementations of the present techniques that formproppant pillars via intermittently adjusting a characteristic of thefracturing fluid may utilize less proppant in a range of 1% less to 50%less as compared to conventional hydraulic fracturing/proppantplacement. The proppant may include proppant coated with resin ortackifier. If so, the resin or tackifier may fuse between neighboringproppant in the pillars at downhole conditions (e.g., temperature andpressure in the wellbore and subterranean formation) to advance orpromote stability of the pillars. The fusing of the resin (or tackifier)among the proppants may give stable proppant pillars. The proppant mayhave hydrophobic coating, wherein to form the pillars may involveagglomeration of the proppant by hydrophobic interaction via thehydrophobic coating. The agglomeration may give pillar stability. Inimplementations, the agglomeration of the proppant (e.g., bindingtogether of the proppant) increases stability of the pillars. Theproppant may be ceramic-coated proppant, ceramic-coated sand,resin-coated proppant, resin-coated sand, or any combinations thereof.These differing proppant may have different respective density. Otherproppant types are applicable, also potentially at different densities.The proppant may be the various proppant types and coatings describedherein. In implementations, the characteristic of the fracturing fluidintermittently adjusted to form the pillars in the fractures may bedensity of the proppant conveyed in the fracturing fluid. Proppant atdifferent density may have a different settling rate. The density of theproppant conveyed in the fracturing fluid can be altered by addingproppant having a first density to the fracturing fluid for a first timeperiod of the sequence and adding proppant having a second densitydifferent than the first density to the fracturing fluid for a secondtime period of the sequence. In implementations, the characteristic ofthe fracturing fluid intermittently adjusted may be size of the proppantconveyed in the fracturing fluid. If so, pillars may be formed atdifferent depths in a vertical fracture where the fractures includevertical fractures. Lastly, the fracturing fluid may have sacrificialsuspending agents. The suspending agents may be degradable material. Thesuspending agents may be in the form of fiber or particles, or both.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made without departingfrom the spirit and scope of the disclosure.

What is claimed is:
 1. A method of hydraulic fracturing with aviscoelastic surfactant (VES)-based fracturing fluid, comprising:pumping the VES-based fracturing fluid through a wellbore into asubterranean formation; hydraulically fracturing the subterraneanformation with the VES-based fracturing fluid, thereby generatingfractures in the subterranean formation; conveying proppant in theVES-based fracturing fluid through the wellbore into the fractures; andintermittently altering rheology of the VES-based fracturing fluidconveying the proppant to form pillars of proppant in the fractures. 2.The method of claim 1, wherein intermittently altering the rheologycomprises intermittently altering concentration of VES in the VES-basedfracturing fluid to form the pillars.
 3. The method of claim 1, whereinintermittently altering the rheology to form the pillars comprisesintermittently altering concentration of salt in brine incorporate intothe VES-based fracturing fluid.
 4. The method of claim 1, whereinintermittently altering the rheology to form the pillars comprisesintermittently altering a type of salt added to the VES-based fracturingfluid.
 5. The method of claim 1, wherein intermittently altering therheology comprises intermittently altering concentration of acrosslinker in the VES-based fracturing fluid to form the pillars. 6.The method of claim 1, wherein the rheology comprises viscosity orviscoelasticity, or a combination thereof.
 7. The method of claim 1,wherein the rheology comprises viscosity.